Text

Forwards Draft Rept on Risk Evaluation of Loss of Spent Fuel Pool Cooling at Plant
	ML17158A633
Person / Time
Site:	Susquehanna
Issue date:	04/07/1995
From:	Vo T; BROOKHAVEN NATIONAL LABORATORY
To:	Palla R; Office of Nuclear Reactor Regulation
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ML17158A634	List: ML17158A633;
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	NUDOCS 9504250393
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'".".'.Balelle Pacific Northwest Laboratories Battelle Boulevard P.O. Box 999 Richland, Washington 99352 Telephone (509t 372-413.4 April 7, 1995 Mr. Robert L. Palla Nuclear Regulatory Commission Office of Nuclear Regulatory Regulation One White Flint North Mail Stop 8H7 Rockvi lie, Maryland 20852

Dear Bob:

Attached please find a copy of our latest report on Risk Evaluation of Loss of Spent Fuel Pool Coolinng Susquehanna. If I can provide any additional information, please let me know.

Sincerely, Truong Vo, Ph.D.

Project Manager attachment cc: George Vargo (PNL); w/o attachment Bryan Gore (PNL); w/o attachment Mitch Cunningham (PNL); w/o attachment 9504250393 'al50420 PDR ADQCtt'5000387 PDR

RISK ANALYSIS FOR SPENT FUEL POOL COOLING AT SUSQUEHANNA ELECTRIC POWER STATION T. R. Blackburn T. M. Mitts H. K. Phan T. V. Vo, Project Manager October 1994 Prepared for Risk Applications Branch Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission under Contract OE-AC06-76RLO 1830 Pacific Northwest laboratory Richland, Washington 99352

ABSTRACT This report provides an evaluation of potential loss of spent fuel pool cooling events at Susquehanna Steam Electric Station (SSES). The evaluation estimates the likelihood of a loss of spent fuel pool cooling event at SSES and the associated probability of spent fuel pool heat up to near boiling conditions. The evaluation also includes a qualitative assessment of the conditional contribution to core damage from such events and an order-of-magnitude core damage frequency estimation.

This evaluation is performed under contract to the NRC to support evaluation of potential generic issue (PGI) 93-01 regarding safety impact of loss of spent fuel pool cooling incidents. This analysis was performed to assess the risk significance of event sequences that involve a loss of spent fuel pool cooling. The analysis investigates allegations and concerns identified in the 10 CFR 21 report filed by two former contract employees which alleged SSES has design deficiencies associated with spent fuel pool cooling which make it susceptible to unsafe conditions.

The analysis addresses SSES plant conditions that existed prior to the 10 CFR 2l (Code of Federal Regulations) report and also addresses current plant conditions. Data for this analysis was obtained from Pennsylvania Power and Light Company, the SSES licensee, and from other sources of probabilistic risk assessment information. The Integrated Reliability and Risk Analysis System (IRRAS) computer code was used to aid in performing the analysis. This report describes background for the evaluations performed, the methodology used in the evaluation, the input data and modeling used for analyses, the analyses techniques and results, and the conclusions.

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EXECUTIVE

SUMMARY

Back round and Ob 'ectives This draft report contains risk analysis information for the Susquehanna Steam Electric Station (SSES) in support of the U. S. Nuclear Regulatory Commission (NRC) evaluation of the claims made in a Title 10 of the Code of Federal Regulations (CFR) Part 21 (Part 21) report concerning spent fuel pool cooling (SFPC) systems inability to meet regulatory requirements. The Part 21 report and supplemental letters claim that SSES has design flaws which under certain design bases accident conditions could cause loss of SFPC with a subsequent detrimental effect on components required for safe operations. These conditions could lead to eventual core damage and eventual offsite radioactivity releases. This project supports the NRC evaluations by performing risk and reliability analyses to provide realistic estimates of the following:

1) the likelihood of the various initiators occurring that could lead to loss of SFPC system,

2) the likelihood of the most important sequences leading to inadequate SFPC from normal and back-up systems,

3) the likelihood of the most important sequences leading to inadequate core cooling,

4) the consequences of these events in terms of core damage.

This draft report identifies and estimates the frequency of initiating events and accident sequences causing SFP heat-up to near boiling conditions and the potential for the important sequences to contribute to core damage at the SSES site.

The SSES site is located near Berwick, Pennsylvania. The power plant consists of two General Electric BWR-4 (Boiling Water Reactor) nuclear reactors, each rated at 3293 HWt with an electric generation output of 1050 MWe. Each unit has a spent fuel pool (SFP) capable of holding 2840 fuel assemblies. The SFPs are both located in the common reactor building. Normal cooling for the SFPs is provided by two independent spent fuel pool cooling systems. Backup cooling to the SFPs is provided from the residual heat removal (RHR) system.

Cooling to both pools may be accomplished by SFPC or RHR system of one unit by connecting the pools via the shipping cask pit. In the worst case, without SFPC or RHR providing closed loop cooling for the SFP, boiling can provide decay heat removal from the SFPs with makeup provided from emergency service water (ESW) or other systems.

Summar of Overall Nethodolo The analysis uses probabilistic risk assessment (PRA) procedures as described in Nuclear Regulation/Contractor Report, NUREG/CR-2300, (American Nuclear, Society [ANS] and Institute of Electronics and Electrical Engineers [IEEE]

1983). This technique was used to estimate the likelihood of various

initiating events that can cause a loss of SFPC to lead to near boiling conditions in the SFP. The approach was continued to provide an order-of-magnitude estimate of the likelihood that the most important event sequences could lead to failure of emergency core cooling equipment and the corresponding conditional core damage frequency.

The analysis includes review of plant specific and general industry information to identify events and plant conditions impacting the requirements and characteristics of plant structures, systems, and components used for cooling for the SFPs and those that can provide cooling for the reactor core.

The information gathered is reviewed and PRA guidance used to estimate the potential for failure of the normal and back-up systems used for cooling the SFPs and those that can provide cooling to the reactor core. The analysis is performed for "As-Found" plant conditions that represent the status of plant procedures, hardware, and, loss of SFPC issue awareness at SSES prior to the Part 21 report and for "As-Fixed" conditions that reflect the current status of plant procedures, hardware, and loss of SFPC issue awareness at SSES.

The analysis process involved reviewing information, developing plant logic models to represent plant response to initiating events, making assumptions necessary to bound the analysis, evaluating data, and quantifying to estimate probabilitie '. The information reviewed includes design and operation documents that describe the plant layout, configuration, procedures, and probabilistic risk assessment. Information from published PRAs of other plants was also reviewed. Additionally, two plant walkdowns were performed to gather information. The plant conditions to be considered were determined from evaluations of recent refueling outage information. This was used to determine the system success criteria that are used in the plant logic models.

Because of the different operating conditions and related success criteria, the model was broken down into Cases. Each Case represents a unique set of conditions that r'equire separate modeling. Selection of the Cases is based on the different decay heat levels present in the spent fuel pools, the available capacity to remove this heat via the spent fuel pool cooling system, the availability of RHR, and the plant operating condition. Tables ES. 1 and ES.2 summarize the Cases for the As-Found and As-Fixed conditions. Note that the model was developed for the site, but the Unit 1 and Unit 2 designators are modeling artifacts and do not represent the actual Units at the site. In the model, Unit 1 experiences all the outages, and Unit 2 is always operating.

The plant's response to the initiating events was modeled with event trees, and the likelihood of failures in the various paths of the event trees were estimated from fault trees that model the systems and from human reliability analyses that model the operator actions. The failure probability values used in the fault trees were obtained from the data analysis and human error probability values were obtained using guidance from the Accident Sequence Evaluation Program Human Reliability Analysis (ASEP HRA) methodology. The IRRAS PRA software and commercial spreadsheet software were used to analyze and quantify the logic models with the entered failure data. The results were tabulated and evaluated to determine insights regarding the major contributors in the failure sequences.

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As-.Found condition. The Pipe Break, Seismic, and Flooding events in As-Fixed plant conditions each contribute about 3% to 5%. The remaining initiating events for both the As-Found and As-Fixed plant conditions each provide a contribution of about 1/ or less.

The overall estimated NBF for the SSES site decreases from the As-Found to the As-Fixed plant conditions due to the changes made since the time the Part 21 report was submitted. This decrease is from 6.8E-5 per plant year in As-Found conditions to 2.1E-5 per plant year for As-Fixed conditions.

The dominant contribution to NBF occurs in Case 1 (both units under normal operation) for both As-Found and As-Fixed plant conditions, with about 34%

contribution and 45% contribution, respectively. The NBF contribution during Case 3 (both SFPs cooled by the operating unit's SFPC system with RHR of the shutdown unit not available for SFPC operation) is also large at approximately 31/ for As-Found conditions and 23% for As-Fixed conditions. The NBF contribution in Cases 4 and 5 together for the As-Found condition is approximately 28%. The Case 4 contribution in As-Fixed condition is approximately 23%. This could change significantly if refueling practices in terms of heat load admitted to t: e SFP(s) and outage management practices in terms of equipment taken out of service were changed from the conditions assumed for this analysis. The SSES refueling or forced outage shutdown practices in the future may not follow those assumed in this analysis because of the larger decay heat loads that could occur from fuller SFPs, longer operating cycles, fuel shuffle practices, or required Nuclear Steam Supply System (NSSS) draindown during hot climate conditions. These issues could easily cause significant changes to both the loss of SFPC NBF and the corresponding contributions to CDF.

The accident sequences with a total estimated NBF of greater than 1.0E-6 per year and any cases having estimated time to reaching near boiling conditions of less than 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months are evaluated to estimate the potential for contributing to core damage. The overall estimated CDF values for these most important event sequences for As-Found plant conditions are low at approximatel'y 5.0E-B per year from eleven event sequences. The estimated contribution to CDF for As-Fixed conditions is estimated at approximately 1. 1E-8 per, year, from eight event sequences. These estimated CDF values are approximate and reflect the order-of-magnitude nature of this analysis.

The analysis results reflect the large number of normal and alternate systems that are available for cooling the SFP(s) and for cooling the reactor core.

The analysis results also reflect the large amounts of time available after the initiating event before the loss of SFPC could lead to near boiling conditions. This time period ranges from a low of 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months for the largest heat load conditions to well over 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months for most of the remainder of the operating cycle.

The failure likelihood values used in the event trees are dominated by human errors. The human error probability estimates associated with these operator actions are significantly larger than the corresponding hardware failure

'probability estimates from the system fault trees. Human actions for As-Fixed plant conditions have better procedural guidance than for the As-Found plant

conditions based on the improvements made and the increased level of awareness about loss of SFPC issues. Because human performance has a large contribution to the NBF and approximate CDF results, additional enhancements in various procedures could help reduce the likelihood of developing near boiling conditions in the SFP(s) and of isolating the steam release from a boiling SFP.

The risk assessment was performed using available SSES plant-specific information and relevant data sources. The preliminary results indicate that the estimated SSES site NBF and core damage contribution estimates are quite low. Due to schedule and budget constraints, detailed sensitivity, as well as uncertainty analyses were not addressed. The numerical results are approximate and plant-specific and should be interpreted cautiously. The results do suggest additional enhancements that are believed to have merit in reducing the likelihood of developing near boiling conditions in the SFP(s) and in isolating the steam release off a boiling SFP. All the enhancements involve providing procedural guidance. The additional procedural guidance includes, use of an alternate back-up cooling mechanism for the SFP(s),

isolation of Heating Ventilation and Air Condition (HVAC) Zones 1 and 2 from Zone 3, emergency diesel generator (EDG) backed power to the non-safety bus that powers a SFPC system, and resourceful alternatives for preventing the steam from a boiling SFP from spreading to the reactor building.,

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Table ES.5 SSES Site As-Found Order-of-Magnitude Estimations of CDF Hear Boiling Isolation/ ECCS Failure Equipment Conditional Frequency Recovery Outside Annual CDF Reactor Estimation Buildin Ran e From HBF 1.0 - 0.01 1.0 - 0.1 0.1 - 0.001 LOOP Case 3 3.1E-06 O.l 1.0 0. 01 3. IE-09 LOOP Case 4 9.5E-07 '0. I 1.0 0.01 9.5E-IO LOOP Case 5 I. IE-06 0.1 1.0 0.01 I. IE-09 EXLOOP Case 3 8. IE-06 0.1 1.0 0.01 8. IE-09 EXLOQP Case 4 3.2E-06 0.1 1.0 0.01 3.2E-09 EXLOOP Case 5 7.9E-06 0.1 1.0 0.01 7.9E-O9 LOCA Case 3 8. IE-06 0.1 1.0 0. 01 8. IE-09 LOCA Case 4 B.BE-07 0.1 1.0 0.01 B.BE-IO LOCA Case 5 3.1E-06 0.1 1.0 0.01 3. IE-09 Seismic Case I 5. BE-07 0.5 0.9 0. 05 1. 3E-08 LOCA w/LOOP Case 3 8.3E-07 0.1 1.0 0.01 8.3E-IO Total Estimated As-Found COF 5.0E-OB Table ES.6 SSES Site As-fixed Order-of-Magnitude Estimations of COF Hear Boiling Isolation/ ECCS Failure Equipnent Conditional Frequency Recovery Outside Annual COF Reactor Estimation Buildin Range From HBF 1.0 - 0.01 1.0 - 0.1 0.1 - 0.001 LOOP Case 3 8.5E-07 0.1 1.0 0.01 8. 5E-10 LOOP Case 4 4.6E-07 0.1 1.0 0.01 4.6E-IO EXLOOP Case 3 3.5E-06 0.1 1.0 Q.QI 3.5E-09 EXLOOP Case 4 2.1E-06 0.1 1.0 0.01 2. IE-09 LOCA Case 3 1.6E-06 0.1 1.0 0.01 1.6E-'09 LOCA Case 4 I.IE-06 0.1 1.0 0.01 I. IE-09 LOCA w/LOOP Case 3 6.9E-07 0.1 1.0 0.01 6.9E-IO LOCA w/LOOP Case 4 4.6E-07 0.1 1.0 0.01 4.6E-IO Total Estimated As-Fixed COF 1. I E-08 Xl l

Acronyms ANS American Nuclear Society ASEP HRA Accident Sequence Evaluation Program BWR Boiling Water Reactor CDF Core Damage Frequency CFR Code of Federal Regulations CRD Control Rod Drive ECCS Emergency Core Cooling System EDG Emergency Diesel Generator ESW Emergency Service Water EXLOOP Extended LOOP FSAR Final Safety Analysis Report HRA Human Reliability Analysis HVAC Heating Ventilation and Air Condition IE Initiating IEEE of Electronics Event'nstitute and Electrical Engineers IPE Individual Plant Examination IRRAS Integrated Reliability and Risk Analysis System LOCA Loss-of-coolant Accidents LOOP Loss of Offsite Power MGL Multiple Greek Letter MNHL Maximum Normal Heat Load MWe Megawatt Electric MWt Megawatt Thermal NBF Near Boiling Frequency NRC Nuclear Regulatory Commission NSSS Nuclear Steam Supply System NUREGlCR Nuclear Regulation/Contractor Report PGE Portland General Electric PGI Potential Generic Issue PNL Pacific Northwest Laboratory PPE(L Pennsylvania Power and Light PRA Probabilistic Risk Assessment RPV Reactor Pressure Vessel RHR Residual Heat Removal SBO Station Blackout SGTS Standby Gas Treatment System SFP Spent Fuel Pool SFPC Spent Fuel Pool Cooling SLC Standby Liquid Control SSES Susquehanna Steam Electric Station SWS Service Water System TSC Technical Support Center VEPCO Virginia Electric PowerACompgmy

TABLE OF CONTENTS Abstract Executive Summary . ~ ~ ~ V Acronymns . X111

1. 0 INTRODUCTION 2.0 ANALYSIS APPROACH . 2.1 2.1 General Information . 2.1 2.2 Analysis Assumptions 2.6 2.3 Near Boiling Frequency Analysis 2.11 2.4 Core Damage Frequency . 2.17 3.0 DISCUSSIONS OF RESULTS 3.1 3.1 Near Boiling Frequency Discussion . 3.1 3.2 Core Damage Frequency Discussion . 3.10 4.0

SUMMARY

AND CONCLUSIONS . 4.1

5.0 REFERENCES

5.1 Xiv

LIST OF FIGU ES Figure ES.l SSES Site As-Found SFP NBF . . . . . . . . . ~ . . . . . xi Figure ES.2 SSES Site As-Fixed SFP NBF , . . . . . . . . . . . . . . xi Figure 2.1 Spent Fuel Pool Arrangement . . . . . . . . . . . . . . 2.3 Figure 2.2 Representative Fuel Pool Cooling (Unit 1 Depicted)-

Simplified Diagram . . . . . . . . . . . . . . . . . . 2.4 Figure 2.3 Representative RHR Cooling (Unit 1 Depicted} - Simplified Diagram . . . ~ . . . . . . . . . . . . . . . . . . . . 2.5 Figure 3.1 Example NBF Event Tree . . . . . . . . . . . . . . . . 3.5 Figure 3.2 SSES Site As-Found SFP NBF . . . . . . . . . ., . . . . 3.8 Figure 3.3 SSES Site As-Fixed SFP NBF . . . . . . . . . . . . . . 3.8 Figure 3.4 Generic CDF Event Tree . . . . . . . . . . . . . . . . 3. 13 xv

ST OF TAB ES Table ES.l Analysis Cases for As-Found Condition . . . . . . V11 Table ES.2 Analysis Cases for As-Fixed Conditions V11 Table ES.3 SSES Site As-Found SFP Near Boiling Frequency . . X Table ES.4 SSES Site As-Fixed SP Near Boiling Frequency X Table ES.5 SSES Site As-Found Order-of-Magnitude Estimations of CDF ~ o ~ ~ ~ i i a ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ X11 Table ES.6 SSES Site As-Fixed Order-of-Magnitude Estimations of CDF ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ X11 Table 2.1 Analysi s Cases for As-Found Condition . ~ 2.14 Table 2:2 Analysis Cases for As-Fixed Conditions . 2.14 Table 3.1 Selected 1nitiating Events and Frequencies 3.1 Table 3.2 SSES Site As-Found SFP Near Boiling Frequency . . 3.7 Table 3.3 SSES Site As-Fixed SFP Near Boiling Frequency . . 3.7 Table 3.4 SSES Site As-Found Order-of-Magnitude Estimations of CDF o ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ . 3.14 Table 3.5 SSES Site As-Fixed Order-of-Magnitude Estimations of CDF ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ o ~ ~ ~ ~ . 3.14 XV1

1. 0 INTRODUCTION l.l Background According to a report filed under Title 10 of the Code of Federal Regulations (CFR) Part 2l on November 27, 1992, and supplemented by six additional letters by two individuals formerly under contract to Pennsylvania Power and Light (PPRL) Company, the Susquehanna Steam Electric Station (SSES) Units I and 2 spent fuel pool cooling (SFPC) systems do not meet regulatory requirements. The Part 21 report and supplemental le'tters claim that Susquehanna Units I and 2 have design flaws that, under certain design bases accident conditions, will cause the following:

loss of SFPC resulting in boiling of spent fuel pool (SFP) water failure of the emergency core cooling system (ECCS) and other equipment in the reactor building due to steam releases from the SFP water or due to flooding from collection of condensed SFP water vapors fuel heat-up leading to core damage due to loss of ECCS loss of the water cover over fuel in the SFP, exposure to air, and possible spent fuel damage due to less effective removal of decay heat by air large offsite radioactivity releases from core damage, spent fuel damage, and loss of ECCS and other mitigative features.

The U.S. Nuclear Regulatory Commission (NRC) is evaluating the claims made in the Part 21 report and the additional submittals made. This project supports the NRC evaluations by performing risk analysis to provide estimates of the following:

the likelihood of the v'arious initiators occurring that could cause loss of SFP cooling the likelihood of event sequences leading to inadequate cooling of the SFPs Order-of-magnitude approximations of the most important sequences leading to inadequate reactor core cooling

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the consequences of these events in terms of potential for contribution to the conditional core damage frequency.

1.2 Objective The purpose of this draft report is to provide an analysis of potential loss of SFPC events for the conditions at SSES site prior to the Part 21 report as well as for current conditions at SSES site. This draft 1.1

report estimates the likelihood of various loss-of-SFPC initiating events leading to near boiling conditions in the SFP(s) and assesses the potential for contribution to core damage for the most important sequences. This work is performed in support of evaluating potential generic issue (PGI) 93-01 concerning plant safety for loss of SFPC events.

The analysis addresses SFP and plant operating conditions at SSES prior to the Part 21 report ("As-Found" ), and current ("As-Fixed" ) conditions.

The initiating events considered are the same for both As-Found and As-Fixed plant conditions. Likewise the scope of the analysis for estimating the frequency of events leading to SFP near boiling frequency (NBF) and the potential for contribution to core damage frequency (CDF) is the same for both the As-Found and the As-Fixed plant conditions.

This analysis provides input for regulatory consideration in estimating the safety at SSES and other nuclear power plants. The As-Found portion of the analysis looks back at conditions prior to the Part 21 report to estimate the risk significance of this issue for consideration of potential generic safety implications. The As-Fixed portion of the analysis looks at current conditions and potential future conditions to estimate the risk significance of this issue for consideration of current and future safety implications at SSES.

1.3 Organization This report provides an overall discussion of the significant elements involved in performing the analysis. Section 2 describes the overall analysis approach including assumptions that affect the model. The results are discussed in Section 3. Section 4 provides the summary and conclusions from the analysis. References are listed in Section 5.

Appendices describe additional details for model development, data development, and the evaluation process and results. Appendix A presents the analysis of the case breakdown for the As-found and As-Fixed conditions. The hardware related failures used to quantify system failure likelihood are provided in Appendix B. Appendix C provides the detailed accident sequence discussions for the most important event sequences. Appendix C also contains event trees used for estimating the likelihood of reaching near boiling conditions for each initiating event and the event tree schematic which portrays SSES capabilities for preventing core damage given a SFP at near boiling conditions. The event trees used for NBF estimations use spreadsheet calculations which are included in Appendix C. Appendix D provides the database development used for the NBF analysis and other information including initiating event frequency estimates.

1.2

2.0 ANALYSIS APPROACH Generally, the analysis was performed using probabilistic. risk assessment (PRA) procedures as described in NUREG/CR-2300 (American Nuclear Society [ANS] and Institute of Electronics and Electrical Engineers [IEEE] 1983). Descriptions of the analysis method and steps and the sources of information are. provided in the following subsections.

2.l General Information Plant La out S ent Fuel Pool Confi uration The SSES located by the Susquehanna River near the town of Berwick, Pennsylvania, consists of two 3923-MW General Electric BWR-4 NSSS with Hark II containment designs. Unit I fegan commercial operation in 1983 and Unit 2 in 1985.

The simplified SFPC system arrangement, the simplified schematic diagr ams for the SFPC system, and the key support systems are shown in Figures 2. 1, 2.2, and 2.3, respectively. The spent fuel pools of each unit ara Seismic Category I and are located in each unit's reactor building. 'The reactor buildings share a common refueling area above the refueling floor. The air space above the SFPs is contained within insulated metal siding and buildup roofing on metal decking.

Each unit has a dedicated non-seismic SFPC system that provides normal cooling water to remove decay heat from irradiated fuel stored in the pool by transfer ring this heat to the service water system. The SFPC system also provides filtering and demineralizing services to maintain water clarity, chemistry, and purity conditions within prescribed tolerances ~ The SFPC system is designed to maintain water temperatures less than l25'F for the maximum normal heat-load condition that is associated with 2840 spent fuel assemblies from normal refueling discharges retained in the pool. The decay heat associated with a full fuel offload at 250 hours0.00289 days 0.0694 hours 4.133598e-4 weeks 9.5125e-5 months after plant shutdown from a full operating cycle is termed emergency heat load and requires operation of the RHR system in the SFPC operating mode to provide adequate SFP cooling.

Emergency heat load conditions are not included in this analysis.

In uts from Other PRAs The initiating events (IEs) and their estimated frequencies, event trees, fault trees, and basic event probabilities prepared for this probabilistic risk study used information from The Pennsylvania Power and Light Company (PP&L) SSES Individual Plant Examination (IPE) study and other PRA studies. Specifically, IEs, event tree models, and fault tree models were developed primarily based on information provided by PP&L about SSES. In addition, information was also gathered during meetings with PP&L staff, subsequent plant walkdowns, and other relevant issues raised in the Part 21 report.

2.I

The IE frequency numbers were estimated based on input from the NUREG-1150 (NRC 1989) support documentation as described in the NUREG/CR-4550 PRAs (Bertucio et al. 1990a, 1990b, 1990c, 1990d; Bohn et al. 1990; Drouin et al. 1989; Ericson et al. 1990; Harper et al. 1991; Kolaczkowski et al. 1989a, 1989b; Sattison et al. 1990; and Lambright et al. 1990). Information was also gathered from the SSES IPE and SSES loss of SFPC mini-PRA and from the other IPE information. Basic event probabilities were estimated primarily from data developed for relevant IPE information from Trojan IPE (Portland General Electic [PGE] 1992),

Washington Nuclear Plant WNP-2 IPE (WPPSS 1992), Oconee IPE (Duke Power 1992), Surry IPE (Virginia Electric Power Company [VEPCO] 1991), and from the SSES IPE for the component and system unavailability information.

Plant Walkdowns Personnel from the NRC and Pacific Northwest Laboratory (PNL) met with PPEL on December I, 1993, and again on August 2, 1994 to discuss the status of PP&L's evaluation of the issues raised in the Part 21 report.

During these meetings, PPEL presented an overview of the plant outage and administrative controls, plant systems design, and operations procedures used to maintain cooling to the SFPs including improvements made since the Part 21 report. Following these meetings, the NRC and PNL performed a walkdown of the SFP and refueling area, SFPC system, components used for the RHR SFPC operation mode, SFP area heating venti-lation and air condition (HVAC) systems, equipment inside the reactor buildings that can be used to provide SFP cooling and that can provide core cooling, and equipment located outside the reactor building that can provide SFP and core cooling.

2.2

Spent Fuel Pool Arrangement ESW ESW RHR RHR Leak Tight Gates SFPC SFPC (3 pumps I I (3 pumps 3 heat I I 3 heat I

exchangers) I Cask exchangers)

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Fuel Pool Cooling Simplified Diagram 153019A 1530168 153019A 1530198 153017 To RHRS 153017 153001 To SFPC Unit 2 153002A 1A 153004A 153045 153013 153009A 153006A Heat Exchanger 153010A 153014 153015 Pump 1530028 18 1530048 1530098 1530068 18 '1530108 153016 LV 15300 Heat Exchanger Pump 153009C 153006C 153002C 153004 C 1C 1530toC Pump Heat Exchanger 594010832 Figure 2.2, Representative Fuel Pool Cooling (Unit 1 Depicted)e - Sf'i imp ied Diagram D'ic

RHR System in Fuel Pool Cooling Mode Simplified Diagram 153070A

'153070B 153071A 153071B 151070 HV 151 F016A HV 151 F028A 153060 '153021 HV 151 F017A 153001 PSV 151 F066A HV 151 F006 HV 151 F010A HV 151 HV 151 F004A 151 F031A HV 151 RHR F047A Service HV-151 151 Water F006A Pump F034A Meat Exchanger 1P202A lE206A HV 151 HV 151 F048A HV 151 F010B F006C 151 F031C HV 151 151 F034C PSV 151 F066B Pump 1P202C HV 151 HV 151 F028B HV 151 F004B 151 F031B HV 151 RHR HV 151 F016B F047B Service HV 151 151 F006B Pump Water F034B Meat Exchanger 1P202B IE206B HV 151 F006D HV 151 F048B 151 F031D HV 151 F017B HV 151 151 F034D F004D PumP 1P202D 69401083.1 Figure 2.3, Representative Cooling (Unit RHR 1 Depicted) - Simplified Diagram

2.2 Analysis Assumptions The analysis addresses several potential causes of loss of SFPC and evaluates a variety of possible outcomes depending on the overall plant response and the time period after the initiating event. The scope and depth of the analysis is bounded by the assumptions made. The assumptions are used to clearly define conditions that are evaluated and conditions that are not evaluated. These assumptions are generally based on information provided by PP8L about the design and operation of SSES and also based on the defined scope of the analysis provided by the NRC staff. The major assumptions used in the analysis are listed below.

The list identifies the assumptions used to perform the analysis of As-Found plant conditions first and then lists any additional assumptions or changes in assumptions pertaining to the analysis of As-Fixed plant conditions. Appendix 0 includes an expanded list of these assumptions that states the basis and impact of each assumption.

As-Found Assum tions The assumptions for the "As-Found" condition are listed below.

1. Spent fuel pools (SFP) are not initially cross-connected (i.e.,

gates are installed separating the SFPs) except Case 3 in which the SFPs are assumed to be initially cross connected.

2. The SFPs are successfully cooled when the temperature in the SFP with the higher decay heat load does not exceed 200'F for an isolated SFP, or the temperature of the cooler SFP does not exceed 170'F when the SFPs are cross-connected.

3. The heat removal capability of two or three Spent Fuel Pool Cooling (SFPC) pump and heat exchanger loops is assumed to be two or three times that of one pump and heat exchanger loop, respectively.

4, The heat load offloaded to the SFP is controlled such that the SFPC system maintains the temperature in the SFP within the administrative limit of 115'F. This limit is maintained by controlling: the number of SFPC pumps and heat exchangers on line, the time of the year the refueling is performed which impacts the Service Water System (SWS) temperature and associated SFPC heat exchanger capacity, the amount of fuel offloaded, and the timing after shutdown of core offload, the water volumes connected to the SFPs, and use of RHR in the SFPC assist mode necessary (i.e., outage with full 'core offload under summer if conditions).

5. The heat load admitted to the SFP and pool configurations are controlled such that the time-to-boil after a loss of SFPC is greater than 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months . However, in the past, pool configurations may have been such that time-to-boil could have been between 15 and 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months for up to 10 days.

2.6

The operating cycle for a SSES unit is assumed to be 18 months and the duration of the refueling outage from unit shutdown to startup is assumed to be 75 days.

The Residual Heat Removal (RHR) system of each unit is assumed to have one train dedicated to reactor core decay heat removal for the following initiating events: loss of offsite power (LOOP),

Extended LOOP, SBO, LOCA with LOOP, and Seismic.

The RHR system for a unit that has a LOCA initiating event will not be available for SFPC assist mode.

The initiating event frequency for Loss of SFPC is assumed to include the probability of the operator failing to perform immediate restart recovery actions.

During Case 2, the RHR system is assumed to have one train operating in the shutdown cooling mode. The other train is either aligned for shutdown cooling or out-of-service for maintenance.

In both conditions, RHR is not available for SFPC assist mode operation. The RHR System will be in this latter condition for a total of eight days. When the RHR system is not in maintenance, one train is modeled as being available for SFPC assist to account for shutdown cooling operation providing cooling to the SFPs.

A thirty-day outage for SWS and/or RHR is assumed to occur each refueling outage after the core is offloaded, the reactor cavity gates are reinstalled, and decay heat decreases to within the capability of 2 SFPC pump/heat exchangers (Case 3 Condition).

Although this outage usually lasts only ten-days it is modeled for all of Case 3 (thir ty-days) with the SFPC and RHR systems out-of-service on Unit I and the SFPs cross-connected. This is slightly more conservative than modeling the Unit I SFPC in service with the pools not cross-connected. This small conservatism in the model is based on the assumption that administrative controls do not limit the time the SFPC system is out-of-service.

Five Emergency Diesel Generators (EDGs) are installed at SSES any of which can be aligned to supply designated emergency loads or SFPC system loads for either Unit I or Unit 2.

The SFPC system for one unit can provide adequate cooling for the SFP of the other unit when the gates separating both SFPs from the fuel shipping cask storage pool are removed. This cross-connected cooling arrangement requires a differential bulk water temperature between the SFPs of approximately 30'F to promote adequate water exchange. Additional SFPC system line-up alterations to provide forced delivery of cooling water to both SFPs are not required.

There are two building cranes that can remove the fuel shipping cask storage pool gates, and a qualified crane operator would be available within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of the time requested.

2.7

15. The fuel shipping 'cask storage pool is always maintained full of water.

16. Approximately eight hours are required to place the RHR system in the SFPC assist mode of operation.

17. There are two diesel fire pumps that can provide makeup to either Unit's SFP under SBO conditions.

18. The gates. separating the reactor cavity from the SFP are provided with redundant positive-sealing devices and alarm features with alarm indication of seal leakage and a low SFP level. Any significant loss of SFP inventory would require a concurrent major rupture of both independent sealing devices. This potential fail-ure, as an initiating event for loss of SFPC, is not modeled since it is considered not credible.

19. The system and support system models used maintenance unavailability values representative of normal plant operations for all cases analyzed unless noted otherwise. Refueling outage and associated maintenance activities are assumed to be scheduled and performed such that these systems have availabilities comparable to normal operating conditions.

20. Equipment that is located in the reactor buildings (HVAC Zones 1 and 2) and is critical for performing safety functions will experience heatup after the onset of boiling in the SFP if not isolated from HVAC Zone 3. Successful isolation of HVAC Zone 3 requires that the recirculation system be shut off and the Standby Gas Treatment System (SGTS) be operating. When HVAC Zone 3 is not isolated, the safety equipment in HVAC Zones 1 and 2 reaches equipment failing critical temperatures approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the onset of boiling in the SFP. During refueling outages, the reactor building for the unit being refueled is isolated from HVAC Zone 3 and therefore the safety equipment in that unit will not experience heatup from boiling in the SFPs. With the recirculatiun fans off, the SGTS would fail approximately 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months after the SFP begins to boil and the ECCS equipment would fail approximately 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the SFP begins to boil.

21. A reactor scram does not occur coincident with the loss of SFPC initiating event. Plant management is assumed to direct a plant shutdown at either, the approximate time of onset-of-boiling in the SFP or when the area temperature in HVAC Zone 3 reaches 125'F, whichever occurs first.

22. A reactor scram occurs coincident with all initiating events except loss of SFPC. Safety functions begin at the time of the reactor scram as does the start of SFP heatup.

2.8

23. The condensate and feedwater systems have all their active components necessary for post-scram alignment feeding/m-keup to the reactor pressure vessel located in the turbine building and the turbine building does not experience heatup in response to SFP heatup. The condensate and feedwater systems are also assumed to be failed after a seismic event or loss of offsite power.

24. The flood, loss of SWS, and pipe break initiating event impacts are considered local events impacting only the SFPC equipment.

Plant wide floods, loss of SWS, or pipe breaks with global effects as well as the potential for consequential damage to other safety-related equipment from these events was not 'considered.

25. Several other methods exist for backup SFPC that are not credited in the model. These methods would prevent SFP boiling or delay the time to SFP boiling conditions and include:

Feed and bleed to SFPs. Feed is provided through Emergency Service Water (ESW) (hard piped and EDG backed) or using fire hose (requires operators to run hose reel to SFPs or to hook up to ESM hard pipe). Bleed is via the overflow through the SFP skimmer surge tank line.

Use the diesel powered fire water pumps for discharge to the SFPs through connection to existing hard pipe systems (i.e.,

ESM).

Use of RHR in the shut down cooling mode of operation with

, discharge to the Reactor Pressure Vessel (RPV) and simultaneously to the SFPs (although not proven to prevent SFP boiling it would certainly delay the heatup).

26. Flooding to the reactor building from SFP condensate and/or overflow is directed to the reactor building sumps and this water is isolated from Emergency Core Cooling System (ECCS) equipment in the reactor buildings except one train of core spray.

27. The Technical Support Center (TSC) is manned and operational within one hour after the initiating event. The TSC staff will facilitate preparation of appropriate recovery action procedures to support mitigation of the event.

28. SFP level and temperature indication in the control room was not improved.

29. The HVAC ductwork low points did not have drains.

30. The procedures for placing RHR in the SFPC assist mode did not require raising the SFP level before running the RHR system in the SFPC assist mode.

2.9

3I. The LOOP emergency procedure did not prompt the operators to consider that the SFPC needs to be restarted.

32. The administr ative controls to maintain at least 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months to SFP

'boiling under a loss of SFPC were not formally controlled or documented.

33. The emergency procedures suggest a variety of ways to maintain core cooling in the event the ECCS systems failed, including:

feedwater, condensate, Core Damage Frequency (CRD) maximized, RHR-SWS cross-tie, fire water system, CRD from other unit, ECCS keep fill system, Standby Liquid Control (SLC) boron tank, SLC demineralized cross-tie.

34. Support system requirements are based on matrix information provided by SSES taken from the IPE.

35. The aluminum siding at some locations in the reactor building has hinged panels that would pivot out and relieve pressure in the building due to the steam environment and thus help to remove energy and reduce temperature.

As-Fixed Assum tions The assumptions for the As-Fixed conditions differ from the As-Found conditions as outlined below.

Spent fuel pools are initially cross-connected (i.e., gates that could separate the SFPs have been removed) for the entire operating cycle except as may be necessary for some off-normal or emergency situation.

2. SFP level and temperature indication in the control room has been improved.

3. The HVAC ductwork has low point drains.

4. The procedures for placing RHR in the SFPC assist mode require raising the SFP level before running the RHR system in the SFPC assist mode.

5. Th e LOOP emergency procedure does prompt the operators to restore cooling to the SFPs.

The administrative controls to maintain at least 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months to SFP boiling under a loss of SFPC are formally controlled and documented. This may require use of RHR in the SFPC assist mode for a full core offload under summer conditions.

2.3 Hear Boiling Frequency Analysis The methods and approach used to perform the analysis of near boiling frequency involves the tasks identified below.

Model Develo ment The SFP near boiling frequency (NBF) is estimated using event trees to model the sequences of failures in normal and back-up SFP cooling systems that could occur after the initiating event and result in near boiling conditions in the SFP. The event trees are developed based on SSES plant design information, input from other PRAs, and a plant walkdowns at SSES. The IE, event tree, and fault tree comprise the framework for the model used to evaluate loss of SFPC events at SSES. This model was developed to analyze a range of possible plant and site conditions for SSES Units I and 2 to estimate the likelihood of developing near boiling conditions in the SFPs that is associated with potential loss of SFPC scenarios. Various SFP cooling requirements are considered for Units I and 2 to address the As-Found and As-Fixed plant conditions and associated refueling conditions.

Initiatin vent The IE is the first event-tree heading and reflects input from the review of available information and consideration of allegations made in the Part 21 report. The technique used to identify initiating events involves determining occurrences such as system disturbances or failures that cause a loss of the SFPC function to one or both SSES units. The analysis considers any potential cause of a loss of SFPC within reason and estimates their likelihood of occurrence. Potential causes were identified from:

reviews of the concerns raised in the 10 CFR 21 report and associated documentation; reviews of the SSES IPE and loss of SFPC mini-PRA (PP&L 1993); :he SSES walkdowns; and review of other IPEs and PRAs. Some of the initiating events considered (i.e., models that include LOOP) involve a loss of SFPC for both units, while other scenarios (i .e., pipe break, internal flooding, loss of coolant accident [LOCA], SFPC system failures, and loss of SWS) cause a loss of SFPC for only one unit. The initiating events that cause a loss of only one unit's SFPC system, have their frequencies doubled to account for the two-units at the SSES site.

All initiating event frequencies apply to a one year period and are across the cases analyzed according to the normalized annual time spent in the conditions of each case.

vent Trees The event trees present the possible combination of system successes and failures that display the various sequence of events following each initiator. The event tree headings represent func-tions performed by specific systems and associated operator 2.11

actions. A response to any IE is successful when adequate SFPC is restored in time to prevent the SFP temperature from reaching 200'F (refer to Appendix A). Adequate cooling for the SFP is dependent on the SFP configuration and associated heat-load conditions analyzed. The event trees follow the guidance of NUREG/CR-2300 for model development. These event trees were developed based on the best available information from PPEL on SSES, other PRA data, and plant walkdown information. Various SFP cooling requirements are considered for Units I and 2 to address the As-Found and As-Fixed plant conditions and associated plant operational and refueling conditions analyzed (cases).

~ SFP Deca Heat valuat'on and Case Selection The analysis performed addresses the cases selected to bound the full range of heat loads in the SFPs that are consistent with controls over core offload at SSES. Selection of the Cases is based on the different decay heat levels present in the Spent Fuel Pools (SFP), the available capacity to remove this heat via the Spent Fuel Pool Cooling System (SFPC), the availability of RHR, and the plant operating condition. Successful cooling of the SFP(s) is based on maintaining the pools below a temperature of 200'F when the pools are not cross-connected or below a temperature of 170'F in the SFP bei'ng directly cooled when the SFPs are cross-connected. It is assumed that maintaining the pool being directly cooled below 170'F is adequate to ensure the second pool does not exceed 200'F. According to standard practices at SSES, fuel is not offloaded to the SFP until the time-to-boil given a loss of SFPC is more than 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months , and the total heat load is within the capacity of the available pump/heat exchangers to maintain the SFP temperature within the administrative limit of 115'F. The first requirement, while in the Final Safety Analysis Report (FSAR), was not necessarily proceduralized in the As-Found conditions and circumstances may have existed early in some outages where the time-to-boil given a loss of SFPC could have been as low as 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months . However, conditions in which the time-to-boil was less than 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months would not have lasted. for mmore re th an 10 days.

The SFPC system is designed to maintain the fuel pool water temperature below 125 F at a Maximum Normal Heat Load (NNHL). The MNHL is based upon filling the pool with 2840 fuel assemblies from normal refueling discharges and 184 fuel assemblies are offloaded from the active core within 160 hours0.00185 days 0.0444 hours 2.645503e-4 weeks 6.088e-5 months after shutdown (FSAR T bl 9.1-2b ).. In the FSAR, full core offloads are considered Emergency Heat Load (EHL) conditions which generally credits th RHR t for fuel pool cooling. The model was built on review of previous outages that indicate full core offloads are normally conducted with decay heat loads in excess of the HNHL, but less than the EHL. These conditions have been acceptable because of 1 ower w th an desi'g n basis'WS inlet temperatures and corresponding increased SFPC system capacity. This evaluation is based on information 2.12

from the recent Spring 1994 outage (SSES U26RIO) with some modifications to provide generic coverage of other previous outages. The representative outage schedule and plant conditions assumed for this analysis are summarized below.

Day 0 Plant shutdown, RHR in shutdown cooling, SFP being cooled by 1 pump/heat exchanger combination.

Day 8 One loop of RHR unavailable for maintenance.

Other train still providing shutdown cooling.

Day 15 Fuel offload complete. Three pumps/heat exchanger required to cool SFP. Both loops of RHR available.

Day 25 SFP isolated from reactor cavity and other SFP (Activity 4).

Day 35 Activity 4 exited (by cross-connecting with other SFP), heat load has decayed to the point that 2 pumps/heat exchangers can handle load.

SFPC and RHR systems are taken out-of-service for maintenance. Cooling of SFP is dependent on pumps from other SFP via cross-connect.

Day 65 SFPC restored to service. Fuel reload completed. One pump/heat exchanger can carry the heat load.

Day 75 Unit restored to power.

The plant information described above was used to define the cases that are analyzed in this report. The differences between As-Found and As-Fixed plant conditions are also considered which results in the two sets of cases evaluated. Development of the cases is discussed in detail in Appendix A. These cases and the corresponding plant conditions are summarized in the following Tables 2.1 and 2.2.

2.13

Table 2.1 Analysis Cases for As-Found Condition Unit 2 Unit I All Cases Case 1 Case 2 Case 3 Case 4 Case 5 Plant Condition 0 cretin 0 eratin Shutdown Shutdown Shutdown Shutdown Ouration (normalized to 1 year) 8768 6368 800 960 320 320 (hrs) t Pumps Initially running (SFP 1 1

<115 F fP s Re uired SFP <<200 F) I I SFPC Availabilit Yes Yes Ko Yes Yes RKR Availability (0 Loops) 1 1 0-8 Oays 1-17 Oa s Time-to-Boil (hrs) >50 >50 >50 >>25 >25 15 - 25 Table 2.2 Analysis Cases for As-Fixed Conditions Unit 2 Unit I All Cases Case 1 Case 2 Case 3 Case 4 Plant Condition 0 eratin 0 eratin Shutdown Shutdown Shutdown Ouration (normalized to I year) 8768 6368 800 960 640 (hrs)

P Pumps Initially running (SFP

<115 F)

I P s Re uired (SFP <200 F)

SFPC Availabilit Yes Yes Yes No Yes RKR Availability (8 loops) 0-8 Oays 1-17 Oa s Time-to-Boil (hrs) >>50 >50 >50 >25 >25 2.14

Fault Trees The systems and components that are procedurally used to provide SFPC were explicitly modeled with fault trees. The following paragraphs summarize the fault tree models. Details of the fault tree model inputs are provided in Appendix B. Fault trees are used to determine the probability of system failures. The fault trees developed for the analysis include basic component failures, instrumentation and control failures, support system failures, maintenance unavailabilities, some component level operator errors, and common-cause failures.

SFPC - This system provides normal and maximum-normal cooling to the SFPs. All pumps, heat exchangers, and major valves and

'omponents were modeled. Support system interfaces that were modeled include electrical power, room cooling, and SWS cooling to the heat exchangers. The SFPC system pump designs were assumed not to meet single design failure criteria. The SFPC system of Unit 1 and Unit 2 each have three SFPC pumps and heat exchangers which are considered to be initially in service, unless noted otherwise.

RHR System - Under conditions where fuel is in the reactor core during refueling, the RHR system has one train providing shutdown cooling to the core and the other train in shutdown cooling standby lineup (Case 2 conditions).'tandby RHR systems are considered available for cooling the SFPs except when needed in response to the event for the fuel in the reactor core of the operating unit. The RHR system can provide normal and emergency cooling for all possible SFP heat loads. All pumps, heat exchangers, and major valves and components required for the SFPC assist mode were modeled. The support system interfaces estimated include electrical failures, emergency diesel generator failures, and SWS cooling to the RHR heat exchangers.

manual cross-connection of the SFPs - The SFPs can be cross-connected using the building cranes to remove the gates from between the Unit 1 and 2 pools. This action increases the size (adds the volume of the cask stor age pit) and pools'ffective allows cooling from one SFP to cool the other SFP. A fault tree was developed to model the cranes, gates, availability of operators, and availability of electrical power.

As appropriate, a simplified Human Reliability Analysis (HRA) technique was used to estimate human error probabilities associated with performing key operator actions. The human error probabilities for critical actions were estimated following guidance in the Accident Sequence Evaluation Procedure Guidance from NUREG/CR-4772 (Swain 1987) and NUREG/CR-4550, Volume 2 (Harper et al. 1989).

2.15

Data Sources The quantification process uses various sources of data, which are described below for the types of data indicated:

Generic Data - Generic data were extracted from a summary in the existing IPE and other sources. Additional reviews of some of these same sources for BWRs were also conducted. A summary of the values, sources, selected point estimate, and rational for selection is provided in the Componerit-Failure Data table portion of the Fault-Tree Basic Events section of Appendix B.

Plant-Specific, Data - Where available, SSES plant-specific information was used. The Susquehanna IPE was considered as an additional source of generic data values. These Susquehanna IPE values are included in the Component-Failure Data table portion of the Fault-Tree Basic Events section of Appendix B.

For some component and system availabilities, plant specific data were extracted from the Susquehanna SFP mini-PRA (SA-TSY-OOI).

Discussion of the selection of these values is included in the Basic Event Value Generation por'tion of the Fault-Tree Basic Events section of Appendix B.

Human-Failure Data - Human errors can contribute to system failures or otherwise impact the sequence of events such that cooling to the SFP(s) is not recovered. Important human actions are addressed in the values used in the top events of the event trees based on a simplified approach for the treatment of human errors. Proceduralized actions performed in response to evolving plant conditions were modeled as critical actions and were quantified following guidance from the Accident Sequence Evaluation Program (ASEP) provided in NUREG/CR-4772 (Swain 1987).

Longer-tenn actions that involve repairs or innovative recoveries were treated as recovery actions. These actions were quantified based on ASEP guidance and estimations from NUREG/CR-4550 (Harper et al. I991) 'n Appendix C, Section C.5, "Issue 5." Innovative Recovery Actions for Long-Term Sequences Involving Loss of Con-tainment Heat Removal." These techniques lead to human-error probabilities generally in the range of 0.004 to 0.1 for restart-related actions and generally in the range of 0. I to 0.5 for repair or recovery actions. The operator actions associated with use and recovery of cooling systems are combined with the fault tree top event failure probability and entered into the event trees.

Common-Cause Data - Common-cause failures are dependent failures that defeat the redundancy used to improve the availability of plant systems or functions. Common-cause failures will be explicitly depicted in the fault-tree models. However, this analysis does not model all the plant systems. It concentrates on the systems required for SFP cooling. Information regarding 2.16

support systems failures was extracted from the Susquehanna IPE.

Then, the common-cause failure probabilities were calculated from

'independent-failure probabilities and common-cause (beta) factors using the Multiple Greek Letter (NGL) methodology (PGE 1992). See the Common-Cause Data section of Appendix B for a detailed discussion and development of the common-cause probabilities.

Tables in Appendices B,C, and D provide all the top event hardware, human error, and combined failure values used in quantifying the event trees.

Model uantification The Integrated Reliability and Risk Analysis System (IRRAS), a PC-based program developed by the Idaho National Engineering Laboratory for the NRC (Russell et al. 1991), was used to develop and analyze the fault trees and to quantify the accident sequences shown in the event trees leading to near boiling conditions. The fault trees and event trees used to estimate the NBF for each initiating event considered are provided in Appendix D.

Failure Se uences Failure sequences are thos'e event scenarios that progress to near boiling conditions in either or both SFPs after the initiating event due to various combinations of hardware and human errors that prevent restoration of adequate cooling to the SFP(s). The analysis estimates the likelihood of these failure sequences occurring and the time elapsed after the initiating event before near boiling conditions could develop in the SFPs for these sequences. Event sequence timing estimations are described under Section 2.4. These estimations are made for each initiating event considered and for each case analyzed for both the As-Found and the As-Fixed plant conditions. Failure sequences with a total NBF for all cases, of less than 1.0E-6 per year or with an estimated time-to-boil of greater than 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months are considered incredible and are dropped from further analysis. The failure sequences with NBFs greater than 1.0E-6 and with estimated time-to-boil within 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months are analyzed for potential contribution to core damage.

2.4 Core Damage Frequency A qualitative approach is used to evaluate the potential for,the most important event sequences to result in damage to the reactor core. The evaluation describes the timeline associated with the event sequences and identifies the major events and activities that occur or would be likely to occur from the onset of the event to the point where failure to mitigate the event could lead to core uncovery. The timeline associated with these events and activities is approximate and indicates the depth of resources that can be applied in the plant response given the long time periods prior to core uncovery. The systems that are likely to be used to mitigate the event are identified and grouped into 2.12

categories, The categories are based on equipment location and functions. Given near boiling conditions, conservative order-of-magnitude failure probabilities are assigned for overall combined system capabilities for these categories of. systems. These order-of-magnitude conditional failure probabilities are multiplied by the estimated NBF for the event sequences analyzed to yield a bounding estimation of the contribution to the core damage probability from the initiating event.

The results from this evaluation for each event sequence evaluated are summed to obtain the overall contribution to core damage frequency from events causing a loss of SFPC. The magnitude of the results provides an indication of the relative significance of these events in relation 'to other contributors to core damage. The basic activities involved in performing this qualitative assessment of conditional contribution to core damage are described below.

Identif the Most Im ortant Event Se uences The most important sequences are identified by applying screening criteria to the event sequences that involved near boiling conditions in the SFP. The event sequences associated with initiating events which have a total estimated NBF of greater than I.OE-6 per year and also have an estimated time-to-near-boiling of less than 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months after the initiating event are evaluated for potential contribution to core damage as described below.

Identif Barriers to Event Pro ression Events that cause a loss of SFPC and subsequent system failures and human errors that lead to near boiling. conditions in the SFP(s) do not present an immediate threat to the fuel in the SFPs or to the ability to maintain core cooling to the reactor. The SFP would have to essentially boil dry before the spent fuel in the SFPs would present any. radiological threat offsite; this event has been evaluated in NUREG/CR-4982. The equipment in the reactor building providing cooling to the reactor core is not adversely affected by loss of cooling to the SFPs unless the energy released from the SFPs in the form of increased temperature and humidity conditions spreads into the reactor building. The energy released from the surface of the SFPs after a loss of SFPC prior to SFP boiling conditions will be kept from spreading to the reactor building by normal Zone 3 HVAC systems (when operating),

by the SGTS (when operating), and by isolating the recirculation fans (if operating). The effectiveness of these systems at preventing spread of the steam from the SFP surface to the reactor building is decreased and not credited after near boiling conditions have developed. Additionally, the reactor building for a unit that is being refueled is isolated from HVAC Zone 3 to maintain secondary containment integrity for the operating unit.

Therefore steam released into Zone 3 will not spread to the refueling unit's reactor building. The reactor building of a non-isolated unit would experience temperature increase at an increased rate after the SFP(s) begin to boil such that 2.18

temperatures adverse to equipment operation could be reached in rooms containing emergency core cooling equipment as soon as eight hours after the SFP reaches boiling conditions.

Estimate Event Se uence Timin The reactor core would not be adversely impacted from the consequences of an event that leads to loss of SFPC unless the ECCS equipment that has not completed their safety functions were rendered inoperable due to adverse room temperatures. As described above, this is not expected to occur until at least eight hours after. the onset of near boiling conditions in the SFP(s). Near boiling conditions in the SFP(s) would not develop prior to 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months after the initiating event for the largest heat load conditions associated with Case 5 in the As-Found plant conditions. The time to near boiling conditions for Cases 3 and 4 is greater than 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months for both As-Found and As-Fixed plant conditions. The time to SFP near boiling conditions for Cases 1 and 2 is greater than 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months for both the As-Found and As-Fixed plant conditions. The evaluation that develops these times to near boiling conditions is presented 'in= Appendix A. The timelines for the most important event sequences identify the major events and activities that occur or would be likely to occur from the onset of the event to the point where failure to mitigate the event could lead to core uncovery. These timelines and detailed discussions of the progression of the event sequence are provided in Appendix 0 and the results are summarized in Section 3.0. The timelines of events and activities is approximate and indicates the depth of resources that can be applied in the plant response given the long time periods prior to core uncovery.

Estimate ikelihood of Failure of Barriers to Se uence Pro ression The most important event sequences are evaluated to identify a bounding order-of-magnitude range for failures in the following groups or categories of systems:

~

systems and operator actions that could be used to prevent excessive steaming release to the reactor building; normal ECCS equipment and any necessary operator actions in the reactor building; back-up equipment located in the other unit's reactor building or located outside the reactor building that could be connected and aligned to provide reactor core cooling.

The success of any of these categories of systems is heavily dependent on operator actions. The order-of-magnitude ranges and selected values for the likelihood of failure associated with these categories of equipment are estimated based on the consideration of several factors that impact their success. These 2.19

considerations are generally human action performance shaping factors. The factors considered in judging the likely failure range and selecting equipment category failure values include the following:

the number of systems and amount of equipment available that could perform the required function; the degree of perceived importance to plant operators and TSC staff; the dynamic significance of the event sequence with associated competing interests for the operator's attention; The degree of dependence among the human actions taken;

~

the approximate time available to complete the action; the indications available to the operators or TSC staff of plant conditions;

~ the deg'ree of procedural guidance; and the overall plant damage state for the event sequence.

The progression of the most important event sequences are summarized in Section 3.0. Appendix D provides a detailed discussion that describes the potential for these categories of equipment to prevent event progression. Judgement based on consideration of the above factors is used to estimate these .

failure ranges and values in evaluating the failure potential for the human actions over the relatively long time periods associated with these event sequences.

stimate Event Se uence Conditional Contribution to Core Dama e

~Fre nenc The estimated order-of-magnitude conditional failure probability values used for the categories of equipment failures that could potentially prevent event sequence progression are multiplied by the estimated NBF for the event sequence to yield a bounding estimation of the contribution to the core damage probability from the initiating event. Event sequence paths are shown in the generalized event tree for core damage frequency presented in Section 3.0. The sequence paths that include success of one of these mitigative categories of systems have successful outcomes that do not contribute to the CDF.

stimate of Core Dama e Fre uenc Due to SFP Boilin The results from the individual event sequence evaluations are summed to obtain the overall contribution to core damage frequency 2.20

from events causing a loss of SFPC. The magnitude of the results provides an indication of the relative significance of these events in relation to other contributors to core damage. These results are presented in Section 3.0.

2.21

3.0 RESULTS ANO OISCUSSIONS Results are presented and discussed for the areas of initiating event frequency, near boiling frequency, core damage frequency, and sensitivity analysis issues.

3. 1 Hear Boiling Frequency Estimation Results The discussion below presents the results of the individual activities performed to support estimations of NBF. The potential for SFP drainage was considered not credible based on SSES having redundant and diverse features to preclude SFP drainage and the SFPs having redundant and diverse inventory makeup capabilities which reduce the potential for SFP drainage. The risk associated with potential SFP drainage was addressed in detail by NUREG/CR-4982 (Sailor et al. 1987), which provides findings consistent with the above findings and concludes that the risks are low and uncertain.

nitiati Event Fre uenc Discussion The initiating events selected for evaluation in this analysis and the annual frequencies of these initiating events are presented in Table 3. 1 below. Appendix C identifies the sources of information used to quantify these initiating events. The frequency values of these initiating events represent an average of SSES 1PE (PP&L 1991) and industry values selected as appropriate and representative for SSES.

Table 3.1 Selected Initiating Events and Frequencies Initiatin Events and Fre Uencies initiatin Event Fre uenc SFPC Fails 1.57E-4/ r LOOP 7.00E-2/ r Extended LOOP 7.0E-3/yr 0 >4 h 3.5E-3/yr 9 >10 h 1.75E-3/ rg >20 h SBO 2.73E-B/ r LOCA 3.67E-3/ r LOCA-LOOP 2.57E-4/ r LOSVS 2.00E-3/ r Flocdin 3.90E-3/ r Pi e Break 3.40E-3/ r Seismic 6.55E-6/yr 0 ~ 0.69 PGA 4.20E-7/ r 0 >> 0.6 PGA 3.1

Event Trees Used to Estimate the NBF The following discussion summarizes the event-tree headings (top events) used to estimate the NBF for the As-Found and As-Fixed conditions. The event sequence paths depend on the successes and failures associated with the top events that appear in a given event tree. The failure sequences are those that result in the Unit I and/or Unit 2 SFP reaching a near boiling condition. The top events used in the event trees reflect differences in the plant's condition and response to the event. The failure values used for these top events are different for the As-Found and As-Fixed conditions and also vary according to the success criteria which differ for the scenarios and cases analyzed. The event trees used to perform the analysis are presented in Appendix C.

The top events that are used in one or more of the event trees are described below. An example event tree is shown in Figure 3. 1.

E. POW REC: This event is defined as recovery of offsite power within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This event is considered for sequence paths in which the cross-connection event fails or succeeds.

L. POW REC: This event is defined as recovery of offsite power supply after 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , but within 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months . This event is considered for sequence paths in which the cross-connection event fails or succeeds.

5th EDG: This event is defined as use of surplus emergency power supplies to power the appropriate non-safety buses for operating the cranes necessary for crass-connecting the SFPs and to power the SFPC system(s). This event is considered for sequence paths in which the cross-connection event fails or succeeds.

CROSSTIE: This event is defined as cross-connecting the Unit I and Unit 2 SFPs. Actions taken include removal of the gates separating the SFPs, by using one of two refueling building cranes. The cross-connection allows free exchange of SFP water between the pools such that one cooling system provides cooling for both SFPs. This event is considered for only the As-Found condition scenarios, the SFPs are already cross-connected for the As-Fixed condition.

UI SFPC RE: This event is defined as restart recovery that returns the SFPC system to service for Unit I after recovery of power to the appropriate non-safety bus, if necessary. This event is considered for the sequence path in which the cross-connection event fails.

U2 SFPC RE: This event is defined as restart recovery that returns the SFPC system to service for Unit 2 after recovery of power to the appropriate non-safety bus, if necessary. This event is considered for the sequence path in which the cross-connection event fails.

3.2

Ul RHR: This event is defined as placement of RHR in the SFPC assist operating mode for Unit l. It takes approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to complete this action. This event is considered for the sequence path in which the cross-connection event fails.

U2 RHR: This event is defined as placement of RHR in the SFPC assist operating mode for Unit 2. It takes approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to complete this action. This event is considered for the sequence path in which the cross-connection event fails.

Ul REP REC: This event is defined as performing repair actions to the Unit 1 SFPC system or RHR system or necessary support systems placing the repair ed system in service for cooling the Unit 1 SFP.

This event is considered for the sequence path in which the cross-connection event fails.

U2 REP REC: This event is defined as performing repair actions to the Unit 2 SFPC system or RHR system or necessary support systems placing the repaired system in service for cooling the Unit 2 SFP.

This event is considered for the sequence path in which the cross-connection event fails.

ALT COOLING: This event has not been credited in quantifying the near boiling frequency, but represents additional mitigative actions that would likely be performed for sequences involving long time periods. The event is defined as cooling the Unit 1 and Unit 2 SFPs using alternate means that may not be pre-defined in the procedures. The equipment which operations or technical support center staff could use for backup cooling to the SFPs include: the emergency service water system, the fire water system, or pumper truck water supply for establishing feed and bleed cooling. This event is shown for sequence paths in which the cross-connection event fails or succeeds.

COMB SFPC: This event is defined as restart recovery that returns the SFPC system to service for Unit 1 or Unit 2 after recovery of power to the appropriate non-safety bus, if necessary. This event is considered for the sequence path in which the cross-connection event succeeds.

COMB RHR: This event is defined as placement of RHR in the SFPC assist operating mode for Unit 1 or Unit 2. It takes approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to complete this action . This event is considered for the sequence path in which the cross-connection event succeeds.

REPAIR REC: This event is defined as performing repair actions to the Unit 1 or Unit 2 SFPC system or RHR system or necessary support systems placing the repaired system in service for cooling the SFPs. This event is considered for the sequence path in which the cross-connection event succeeds.

3.3

Figure 3. I, "Example NBF Event Tree," shows the basic process used within a commercial spreadsheet program to model event trees with the above top events. Each event tree is characterized by a subject title, initiator title, top event titles, node success and failure values, structured logic diagram, and endstate sequence conditions and values.

The highlighted row on each event tree represents the failure values and is the input to the event tree, all other values are calculated. The row above the highlighted failure row is for the calculated success values. The structured logic of the event tree uses the common event tree practice of modeling failures as the downward path, success as the upward path. Intermediate success and failure values are shown for each node. The first node in the event tree is the initiating event.

Subsequent nodes in the event tree represent the top events. Typically the top events are arranged in'n order corresponding to the system sequential response to the transient although this may not always be the case (e.g., "Crosstied" is always modeled as the first node after the initiating event, but it probably occurs midway through the event). This was done to simplify the modeling of the events by transferring crosstied conditions to another event tree for each initiating event.

The "Endstate" portion of the event tree contains sequence condition designation. The sequence condition designations represent a successfu1 avoidance of near boiling ("ok" column), single unit boiling (" Unit I" and "Unit 2" columns), and both units boiling (" Both Boil" column). 'wo additional columns are provided for sequence transfers to other event trees and comments. Each column is totaled and a numerical check to ensure completeness is calculated at the bottom of the "Comment" column.

Please note that the total NBF does not appear on either of these two rows. A separate row is located at the bottom of each initiating event's "Cross-tied" event tree that provides a total for each sequence designation and the total NBF for the initiating event.

3.4

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Fault Trees and To Events Used to Estimate the NBF The following discussion summarizes the fault-tree top event failure estimations, the human error probability estimations associated with these top events, and the combined top event failure probabilities used to. estimate the NBF for the As-Found and As-Fixed conditions. These combined top event failure probability values are the values entered into the event trees at the corresponding top event.

Simplified fault trees were developed for the SFPC system, the RHR system in the SFPC assist mode, and the SFP cross-connect equipment. The data used to quantify these fault trees is presented, in Appendix B. The resulting system hardware top event tree unavailabilities (hardware failure rates) for the As-Found and the As-Fixed plant conditions for all cases analyzed are presented in Appendix B, Tables B. I and B. II.

The human actions necessary to respond to the initiating events involve operator actions to recover cooling to the SFPs as reflected in the event tree top events. The human error probability estimations for these top events in the As-Found and the As-Fixed plant conditions for all cases analyzed are presented in Appendix D, Tables D. I and D. II.

The overall failure probability for the event tree top events is the sum of the system fault tree unavailabilities and the human ,

error probability values. The combined top event failure probability estimations for the As-Found and the As-Fixed plant conditions for all cases analyzed are presented in Appendix C, Tables C. IV and C.V.

stimated Near Boilin Fre ue~nc The NBF is estimated by performing the NBF event tree calculations. The As-Found and As-Fixed near boiling frequency (NBF) results for the cases considered, the initiating events analyzed, and overall totals are presented in Table 3.2 and Table 3.3. The estimated NBF contributions by initiating event are charted in Figure 3.2 and Figure 3.3.

3.6

Table 3.2 SSES Site As-Found SFP Near Boiling Frequency Fre uenc ( er lant ear)

Initiator Case I Case 2 Case 3 Case 4 Case 5 Total X of total Loss of SFPC 3.4E-OB 4.8E-OB I.OE-07 7.6E-09 7.5E-OB 2.7E-07 0.4X LOOP 2.7E-06 S.IE-07 3.1E-06 9.5E-07 I. IE-06 8.3E-OB 12.3X Extended Loo 1.3E-05 3.7E-06 B.IE-06 3.2E-06 7.9E-06 3.6E-OS 53.3/

SBO 4.0E-09 5.1E-IO 1. IE-09 3.6E-IO 5.2E-IO 6.5E-09 O.OX LOCA 2.9E-06 3.6E-07 B. IE-06 B.BE-07 3.1E-06 1.5E-OS 22.5X Floodin 2.9E-07 6.4E-OB 3.8E-07 1.2E-07 3.2E-07 1.2E-06 1.7X Loss of SMS I.SE-07 3.3E-OB 1.9E 07 5.9E-OB 1.6E-07 6.0E-07 0.9X Pi e Break 2.5E-07 5.6E-OB 3.3E-07 1. OE-07 2.8E-07 I.OE-06 I.SX Seismic <.6 2.6E-07 ?.BE-08 2.0E-O& 2.9E-OB 4.6E-OB 4.3E-07 0.6X Seismic ~>.6 3. IE-07 3.8E-OB 4.6E 08 1.5E-OB 1.5E-OB 4.2E-07 0.6X LOCA w/LOOP 2.9E-06 I.BE-07 8.3E-07 1.7E-07 1.2E-07 4.2E-06 6.2X Total 2.3E-OS S.IE-06 2.1E-OS 5.5E-06 1.3E-OS 6.8E-05 X of total 33.9X 7.5 31.1X B.IX 19.4X Table 3.3 SSES Site As-Fixed SFP Near Boiling Frequency Fre uenc ( er lant ear)

Initiator Case I Case 2 'ase 3 Case 4 Total X of total Loss of SFPC 1. IE-07 1.9E-OB S.OE-OB 4.6E-OB 2.3E-07 I.IX LOOP S.SE-07 7.9E-OB 8.5E-07 4.6E-07 1.9E-OB 9.3X Extended Loo 3.0E-06 4.0E-07 3.5E-06 2.1E-06 9.0E-06 43.2X SBO 4.0E-09 S.OE-IO I.IE-09 7.1E-IO 6.2E-09 O.OX LOCA 1.5E-06 1.7E-07 1.6E-OB 1.1E-06 4.3E-06 20.7X Floodin 2.8E-07 3.8E-OB 3.8E-07 2.3E-07 9.3E-07 Loss of SMS 3.5E-OB S.OE-09 5.4E-OB 2.9E-OB 1. 2E-07 0.6X Pi e Break. 2.5E-07 3.3E-OB 3.3E-07 2.0E-07 8. IE-07 3.9X Seismic <.6 1.2E-07 1.6E-OB 6.9E-Q& 4.4E-OB 2.5E-07 1.2X Seismic >>.6 3.1E-07 3.8E-OB 4.6E-OB 3. IE-08 4.2E-07 2.0X LOCA w/LOOP 1.6E-06 9.6E-OB 6.9E-07 4.6E-07 2.8E-06 13.6X Total 7.7E-06 9.0E-07 7.6E-06 4.7E-06 2.1E-OS X of total 37.0X 4.3X 36.2X 22.4X 3.7

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As-Found NBF Estimation Results The total estimated SFP NBF summed over all five of the cases for all initiating events in the As-Found plant conditions is 6.8E-5 per plant year. Case 1 which represents normal plant operations has the highest contribution to NBF (approximately 34/). This result is due to the relatively large exposure time as compared to the other four cases which represent various heat load conditions and cooling capabilities for the SFPs during a representative refueling outage (refer to Appendix A for case descriptions).

Cases 2 and 4 each contribute approximately 8% to the overall As-Found NBF. Case 3 contributes a large amount at approximately 31%

to the total NBF due to the unavailability of SFPC in one unit because of a SWS outage and assumed unavailability of RHR for cooling the SFPs. Case 5 finishes the As-Found contribution to NBF with approximately 19%.

The results for each case in the As-Found plant condition are dominated by the Extended LOOP event which overall contributes approximately 53% to the NBF. Case 3 is equally dominated by EXLOOP and LOCA, both having and estimated NBF of approximately 8.1E-6 per year. Overall, the second major contributing initiating event is LOCA which contributes about 22%. The LOOP initiating event has a total contributions to the NBF of about 12%, while LOCA with LOOP contributes approximately 6/. Flooding, Pipe Break, and Seismic events each contribute less than 2%, and the remaining initiating events each provide a contribution of 1%

or less.

As-Fixed NBF Estimation Results The total estimated SFP NBF (Table 3.3) summed over all four of the cases for all initiating events in the As-Fixed plant conditions is 2.1E-5 per plant year. Case 1 which represents normal plant operations has the highest contribution to NBF (approximately 37%). This result is due to the relatively large exposure time as compared to the other three cases which represent various heat load conditions and cooling capabilities for the SFPs during a representative refueling outage (refer to Appendix A for case descriptions). Case 3 has a significant contribution due to the assumed unavailabilities in one unit's SFPC due to a SWS outage and of RHR for maintenance. Case 4 contributes approximately 22% to the overall As-Fixed NBF. Case 2 contributes approximately 4% to the total NBF.

The results for each case in the As-Fixed plant condition are also dominated by the Extended LOOP event which overall contributes approximately 42% to the NBF. The second major contributing initiating, event is LOCA which overall contributes about 21%. The LOCA with LOOP initiating event contributes approximately 14% to the total NBF, while LOOP contributes approximately 9%. Pipe Break, Flooding, and Seismic events each contribute between 3/. and 3.9

5% to the total As-Fixed NBF. The remaining initiating events each provide a contribution of less than 1%.

The results show that the overall estimated NBF is decreased by more than a factor of three from the As-Found to the As-Fixed plant conditions. This decrease in the estimated NBF is attributed to the changes made since the time the Part 21 report was submitted. The changes that make this impact on the results include: maintaining the SFPs in a cross-connected configuration,"

improving the overall level of awareness of the potential seriousness of loss of SFPC events if not attended to for long periods of time; improving the guidance in the procedures provided for events involving a loss of SFPC; improving the administrative controls over management of the heat load conditions allowed to exist in the SFPs; and improving the instrumentation provided in the control room.

The results also show that from As-Found to As-Fixed conditions, the contribution to NBF from a loss of SFPC event has shifted slightly to normal plant operating conditions (Case 1). The shift in the degree that the NBF is dominated by Extended LOOP from about 53% in the As-Found conditions to about 43% and in the As-Fixed plant conditions and similar decrease in the LOOP event reflects the decreased reliance on electric power for being able to cross-connect the SFPs. The LOCA event shows a small decrease in the relative contribution to NBF from As-Found to As-Fixed conditi'ons. The LOCA with LOOP event shows a decrease in absolute estimated NBF values, but contributes a larger relative percentage in the As-Fixed case than the As-Found condition.

3.2 Core Damage Frequency Discussion The results from this analysis do not include the contribution to CDF from scenarios involving reactor pressure vessel rupture and/or containment failure. The'se scenarios have a small contribution to the total CDF in the SSES IPE and are considered even less significant for loss of SFPC events which involve relatively long times before increased temperatures develop. Likewise, the risks from non-core-damage plant damage states are not addressed. These event scenarios are believed to involve relatively minor offsite risks based on the low amounts of radioactive materials involved and the integrity of the containment.

The discussion in Appendix C describes the accident progression from initiating event to near boiling conditions and then to potential core damage conditions for each of the most important event sequences. A table depicting an approximate time line of events and likely activities associated with each of these accident progressions is also provided in Appendix C.

The event tree provided in Figure 3.4 shows the failure paths and categories of equipment failures that would be necessary to reach core damage conditions. A brief discussion of the event sequence evaluations 3.10

for estimating the potential for contribution to core damage is provided below. This discussion concludes with an order-of-magnitude estimation of the potential conditional core damage frequency for each major event sequence. The total order-of-magnitude estimation of conditional core damage frequency for all of these most important event sequences is presented in Tables 3.4 and 3.5.

~ Se uence Pro ression Discussion of Most Im ortant Accident

~Se uences The most important accident sequences are those that have an initiating event with a total estimated annual NBF of greater than 1.0E-6 and occur in cases that have estimated time to reach near boiling conditions of less than 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months . Initiating events with a total estimated annual NBF of less than 1.0E-6 are considered'to provide a negligible or insignificant potential contribution to core damage. Likewise, cases estimated to reach near boiling conditions at greater than 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months are considered to have sufficient time to restore cooling to the SFP(s) or to prevent adverse conditions in the reactor building. This certain recovery is credited because of the multiple success paths available, and the extended time in which to mitigate the event. The ECCS equipment required for core cooling will have completed the required safety functions or will be otherwise protected for accident sequences with estimated time to near boiling conditions of greater than 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months . Therefore, this evaluation does not include the potential contribution to core damage from sequences which are negligible contributors (NBF <1.0E-6) or that allow sufficient time for certain recovery (>50 hours to boil).

The evaluations for the most important event sequences first consider the initial plant conditions which impact the sequence path and timing. Next, the activities and events that could occur in the time between the initiating event and reaching near boiling conditions in the SFP are evaluated to estimate the potential for

. early recovery. Once the SFP has reached near boiling conditions, the potential recovery paths from isolation of, the steam released into Zone 3 or from alternate methods of cooling the SFPs are estimated. Additionally; the potential for use of alternate core cooling methods with equipment outside the reactor building or with any surviving equipment in the reactor building is estimated.

Finally, the time to core uncovery is approximated. The analysis

'hen uses the approximations of failure of recovery from these methods to obtain an order-of-magnitude estimation of the conditional contribution to core damage frequency given the initiator. This analysis is shown schematically in the event tree presented in Figure 3.4. This event tree presents the general sequence flow path that could lead to core damage given near boiling conditions. The general functional failures that would have to occur before the sequence could reach a core damage end state and typical order of magnitude estimations of their associated failure likelihoods are as follows: 1

-3.11

Failure of alternate methods for cooling the SFPs that were not credited in the estimation of the NBF as well as failure of operators to isolate Zone 3 from the Unit 2 reactor building. The failure occurs if operators do not implement alternate feed and bleed cooling to the SFPs using one of at least three possible systems and also do not isolate the Zone 3 air space from Zone 2 air space. The likelihood that these actions would fail given the typically long time periods between exceeding the SFP temperature .technical specification limit and failure of ECCS equipment in Unit 2 is generally estimated at 0.1.

Failure of and non-recovery of all Unit 2 ECCS equipment that would normally be capable of providing sufficient long term decay heat removal. .The initial short term post scram functions are completed prior to failure of the ECCS equipment. The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, and other activities is generally estimated at 1.0.

Failure of all equipment outside the Unit 2 reactor building including: feedwater, condensate, standby liquid control, reactor water cl,eanup, fire water, control rod drive maximized, RHR service water, or pumper truck, and ECCS equipment from Unit 1 that could be crosstied to Unit 2 .

Host of these alternate cooling mechanisms are identified in the emergency procedures. The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, and other activities is generally estimated at 0.01.

~ Summar of Conditional Core Dama e Fre uenc Contribution Estimations Based on this type of analysis the resulting conditional core damage frequency contributions from each of the most important event sequences are described below. The event sequences evaluated for conditional core damage frequency contributions also includes those that come close to meeting the screening criteria for evaluation.

The overall order of magnitude estimate of the conditional core damage frequency due to an initiating event is the product of the estimated NBF and the three general functional failure estimation above. The order of magnitude estimated potential for these functional .failures, given SFP boiling conditions, and the associated conditional core damage frequency estimations are summarized in Table 3.4 below for As-Found and As-Fixed conditions. The product provides the estimated CDF contribution for each of the event sequences evaluated.

3.12

Generic Core Damage Frequency (CDF) Event Tree lE Near BoiTing holationl ECCS Failure Equipmsnt'utside Frequency Recovery

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Core Damage Figure 3.4 Generic CDF Event Tree 3.13

Table 3.4 SSES Site As-Found Order-of-Magnitude Estimations of CDF Hear Boiling Isolation/ ECCS Failure Equipment Conditional Frequency Recovery Outside Annual COF Reactor Estimation Buildin Ran e From HBF 1.0 - 0.01 1.0 - 0.1 0.1 - 0.001 LOOP Case 3 3.1E-06 '0.1 1.0 0. 01 3. 1E-09 LOOP Case 4 9.5E-07 0.1 1.0 0.01 9.5E-10 LOOP Case 5 I. IE-06 0.1 1.0 ~ 0. 01 1.1E-09 EXLOOP Case 3 8.1E-OB 0.1 1.0 0.01 8. 1E-09 EXLOOP Case 4 3.2E"06 0.1 1.0 0. 01 3.2E-09 EXLOOP Case 5 7.9E-06 0.1 1.0 0. 01 7.9E-09 LOCA Case 3 8.1E-06 0.1 1.0 0. 01 B.IE-09 LOCA Case 4 B.BE-07 0.1 1.0 0.01 B.BE-10 LOCA Case 5 3.1E-06 0.1 1.0 0. 01 3. 1E-09 Seismic Case 1 5.6E-07 0.5 0.9 0. 05 1.3E-OB LOCA w/LOOP Case 3 8.3E-07 0.1 1.0 0.01 8.3E-10 Total Estimated As-Found COF 5.0E-OB Table 3.5 SSES Site As-Fixed Order-of-Magnitude Estimations 'of CDF Near Boiling Isolation/ ECCS Failure Equi pnent Conditional Frequency Recovery Outside Annual COF Reactor Estimation Buildin Ran e From NBF 1.0 - 0.01 1.0 - 0.1 0.1 - 0.001 LOOP Case 3 8.5E-07 0.1 1.0 0. 01 8.5E-IO LOOP Case 4 4.6E-07 0.1 1.0 0.01 4.6E-10 EXLOOP Case 3 3.5E-06 0.1 1.0 0.01 3.5E-09 EXLOOP Case 4 2.1E-06 ~

0.1 1.0 0.01 2.1E-09 LOCA Case 3 1.6E-06 0.1 1.0 0.01 1.6E-09 LOCA Case 4 1.1E-06 0.1 1.0 0.01 1.1E-09 LOCA w/LOOP Case 3 6.9E-07 0.1 1.0 0. 01 6.9E-10 LOCA w/LOOP Case 4 4.6E-07 0.1 1.0 0.01 4.6E-10 Total Estimated As-Fixed COF 1. IE-08 3.l4

4.0 SUMNRY AND CONCLUSIONS This evaluation was performed under contract to the NRC to support the evaluation of PGI 93-01 regarding the safety impact of loss of spent fuel pool cooling incidents. The evaluation is centered on the SSES because of a 10 CFR 21 report filed by two former contract employees which make allegations that the SSES has designed deficiencies associated with SFPC which make it susceptible to unsafe operations. The evaluation was based on SSES plant-specific information including the SSES IPE and relevant generic data sources.

The standard PRA technique was used for the evaluation.

The likelihood of a loss of, SFPC event at SSES and the probability of the SFP heating up to near boiling conditions have been estimated. Additionally, the event sequences that have the greatest estimated likelihood of the SFP(s) reaching near boiling conditions in a time period of less than .50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months were evaluated to provide an order-of-magnitude approximation of their contribution to core damage. These estimations are based on models that represent the plant conditions in the As-Found state prior to the Part 21 report and models that represent present plant conditions in the As-Fixed state after improvements made in equipment, procedures, and personnel awareness regarding SFPC issues.

Based on the preliminary results of this study, general insights obtained from this .analysis include:

The overall estimated NBF values for the As-Found plant conditions are low at 6.8E-5 per year and have been reduced to 2.1E-5 per year by the changes made for the present state of As-Fixed plant conditions. These estimated NBF values reflect realistic plant conditions and show the benefit of improvements made at SSES for maintaining cooling to the SFPs. A large portion of this benefit is realized by the change that maintains the Unit I and Unit 2 SFPs cross-connected. This change reduces the vulnerability to events involving a loss of offsite power which inhibit the cross-connection. With the SFPs in the cross-connected state, the systems available to provide cooling to the SFPs is essentially doubled for every event and every case. The other improvements made at SSES related to SFPC (i.e., increased level of awareness, better procedures, and enhanced hardware) result in significantly lower estimated human err or probability values for the key operator actions necessary to respond to loss of SFPC events.

2. The overall estimated CDF values for the most important event sequences for As-Found plant conditions are low at 5.0E-8 per year. There are ten event sequences that meet (or come-close to) the screening criteria for consideration for potential contribution to core damage for the As-Found plant conditions. The Seismic events (< 0.6 g and > 0.6g together) were also evaluated for their contributions to core damage because of their unique and severe plant damage state considerations. There are eight event sequences which meet the screening criteria for evaluations of potential for contributions to core damage in the As-Fixed plant conditions and the estimated contribution to CDF from this event sequence is estimated at l.lE-8 per year. These estimated CDF values 4.1

are approximate and reflect the order-of-magnitude nature of this analysis.

The analysis results reflect the large number of normal and alternate systems that are available for providing cooling to the SFP(s) and to the reactor core. The systems that can be used to provide these cooling functions include several that are located outside the reactor building and therefore would not be subjected to adverse temperature conditions from SFP boiling. Many of these systems are also independent of other support systems and therefore are available regardless of the 'lant initiating event (except Seismic). The analysis results also reflect the large amounts of time available after the initiating event before the loss of SFPC could lead to near boiling cohditions. For the As-Found condition evaluation, this time period ranges from a low of 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months for the largest heat load conditions that could be admitted to the SFPs (for a short duration of less than 10 days during a refueling outage) to over 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months for another part of the refueling outage, and well over 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months for most of the remainder of the operating cycle.

The time to near boiling conditions for the As-Fixed conditions is always greater than 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months and usually much greater than 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months .

The event sequences that involve greater than 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months to reaching near boiling conditions are not evaluated further because this allows sufficient time that PPEL can assemble the support necessary to provide event mitigation.

The failure likelihood values used in the event trees are dominated by human errors. Each top heading shown in the event trees requires.

operator action to perfor'm the activity indicated. The operator actions occurring early in the event sequence generally have procedural guidance governing the action. The operator actions occurring later in the event sequence tend to have less procedural guidance, or involve innovative recovery actions that are not proceduralized. The human error probability estimates associated with these operator actions are significantly larger than the corresponding hardware failure probability estimates from the system fault trees. Human actions for As-Fixed plant conditions have better procedural guidance than for the As-Found plant conditions based on the improvements made and the increased level of awareness about loss of SFPC issues. Because the human error probability estimations for these actions are dominant contributors, is believed that further procedural improvements, training, and minor it hardware improvements that aid the operators in handling events involving loss of SFPC would be useful to justify reduced HEP estimations and thus reduce the estimated NBF and CDF values.

Enhancements believed to have merit in effectively reducing the likelihood of developing near boiling conditions in the SFP(s) and in isolating the steam release off a boiling SFP include the following.

Provide procedural guidance for use of an alternate back-up cooling mechanism for the SFP(s) with an independent system such as diesel driven fire suppression.

4.2

Provide procedural guidance for operators to perform the to isolate HVAC Zones I and 2 from Zone 3 given a loss of actions'ecessary SFPC well in advance of reaching near boiling conditions in the SFP(s).

I Provide procedural guidance for operators to provide EOG backup power to the non-safety bus that powers a SFPC system for events involving a loss of offsite power and to restart the SFPC system.

Provide guidance for a resourceful alternative to allowing the steam released from a boiling SFP to spread to the reactor building such as creating an opening in the refueling floor area. siding or roof to allow the steam 'to escape.

Although the dominant contribution to NBF occurs in Case 1 which involves the period of normal plant operation, this could change significantly if refueling practices in terms of heat load admitted to the SFP(s) and outage management practices in terms of equipment taken out of service were changed from the conditions assumed for this analysis. This is illustrated by the relatively large contribution during Case 3 conditions due to the assumed unavailability of the SFPC system and the RHR system for the shutdown unit and the .policy that RHR from a unit experiencing a LOCA is not used to cool the SFPs. This analysis did not address the additional impact that other outage conditions that are based on differing outage management and maintenance practices would have on the CDF contributions. These outage risk contributors and the issue of'shutdown risk management were beyond the scope of this analysis. Nevertheless, the SSES refueling or forced outage shutdown practices may need to change from those assumed in this analysis in order to handle the larger decay heat loads that could occur in the future due.to fuller SFPs, longer operating cycles, fuel shuffle practices, or required NSSS draindown during hot climate conditions.

These issues could easily cause significant changes to both the loss of SFPC NBF and the corresponding contributions to CDF. For this analysis equipment out of service times were based on the information provided by SSES and are representative of actual recent outages.

The risk assessment was performed using available SSES plant-specific information and relevant data sources. The preliminary results indicate that the estimated NBF and core damage contribution estimates are quite low; note that the numerical results are approximate and plant-specific and should be interpreted cautiously. Due to schedule and budget constraints, detailed sensitivity, as well as uncertainty analyses were not addressed.

4.3

5.0 REFERENCES

American Nuclear Society and Institute of Electronics and Electrical'ngineers (ANS L IEEE). 1983. PRA Procedures Guide. NUREG/CR-2300, American Nuclear Society, La Grange Park, Illinois.

Bertucio, R. C. et al. 1990a. Analysis of Core Damage Frequency: Surry, Unit 1 Internal Events. NUREG/CR-4550, Volume 3, Rev. 1, Part 1, Sandia National Laboratories, Albuquerque, New Mexico.

Bertucio, R. C. et al. 1990b. Analysis of Core Damage Frequency: surry, Unit 1 Internal Events Appendices. NUREG/CR-4550, Volume 3, Rev. 1, Part 2, Sandia National Laboratories, Albuquerque, New Mexico.

Bertucio, R. C. et al. 1990c.'nalysis of Core Damage Frequency: Sequoyah, Unit 1 Internal Events. NUREG/CR-4550, Volume 5, Rev. 1, Part 1, Sandia National Laboratories, Albuquerque, New Mexico.

Bertucio, R. C. et al. 1990d. Analysis of Core Damage Frequency: Sequoyah, Unit 1 Internal Events Appendices. NUREG/CR-4550, Volume 5, Rev. 1, Part 2, Sandia National Laboratories, Albuquerque, New Mexico.

Bohn, M. P. et al. 1990. Analysis of Core Damage Frequency: Surry Power Station, Unit 1 External Events. NUREG/CR-4550, Volume 3, Rev. 1, Part 3, Sandia National Laboratories, Albuquerque, New Mexico.

Drouin, M. T. et al. 1989. Analysis of Core Damage Frequency: Grand Gulf, Unit 1 Internal Events. NUREG/CR-4550, Volume 6, Rev. 1, Part 1, Sandia National Laboratories, Albuquerque, New Mexico.

Duke Power. 1990. Oconee Units 1, 2, and 3, Individual Plant Evaluation Submittal Report. Duke Power Company, North Carolina.

Ericson, D. M. et al. 1990. Analysis of Core Damage Frequency: Internal Events Methodology. NUREG/CR-4550, Volume 1, Rev. 1, Sandia National Laboratories, Albuquerque, New Mexico.

Harper, F. T. et al. 1990. Evaluation of Severe Accident Risks:

guantification of Major Input Parameters. NUREG/CR-4550, Volume 2, Rev. 1, Part 2, Sandia National Laboratories, Albuquerque, New Mexico.

Heaberlin, S. W. et al. 1983. Handbook for Performing Value-Impact Assessment. NUREG/CR-3568, Pacific Northwest Laboratory, Richland, Washington.

Kolaczkowski, A. M. et al. 1989a. Analysis of Core Damage Frequency: Peach Bottom, Unit 2 Internal Events. NUREG/CR-4550, Volume 4, Rev. 1, Part 1, Sandia National Laboratories, Albuquerque, New Mexico.

Kolaczkowski, A. M. et al. 1989b. Analysis of Core Damage Frequency: Peach Bottom, Unit 2 Internal Events Appendices. NUREG/CR-4550, Volume 4, Rev. 1, Part 2, Sandia National Laboratories, Albuquerque, New Mexico.

5.1

Lambright, J. A. et al. 1990. Analysis o'f Core Damage Frequency: Peach Bottom, Unit 2 External Events. NUREG/CR-4550, Volume 4, Rev. 1, Part 3, Sandia National Laboratories, Albuquerque, New Mexico.

Pennsylvania Power and Light Company (PP&L). 1991. Susquehanna .Steam Electric Station - Individual Plant Examination. NPE-91-001, Pennsylv'ania Power and Light Company, Berwick, Pennsylvania.

Pennsylvania Power and Light Company. 1993. Fuel Pool Cooling and Cleanup System. In Susquehanna Operating Procedure, OP-135-001, Rev. 16.

Pennsylvania Power & Light Company, Berwick, Pennsylvania.

Pennsylvania Power and Light Compan'y. 1993. Susquehanna Mini-PRA. SA-TSY-001, Rev. 0. Pennsylvania Power & Light Company, Berwick, Pennsylvania.

Pennsylvania Power and Light Company (PP&L). 1993. Susquehanna Steam Electric Station - Final Safety Analysis Report. Pennsylvania Power and Light Company, Berwick, Pennsylvania.

Pennsylvania Power and Light Company. 1993. Susquehanna Steam Electric Station Individual Plant Evaluation. NPE-91-001, Pennsylvania Power & Light Company, Berwick, Pennsylvania.

Pennsylvania Power and Light Company. 1993. RHR Operation in Fuel Pool Cooling Mode. In Susquehanna Operating Procedure, OP-149(249)-003, Rev. 11.

Pennsylvania Power & Light Company, Berwick, Pennsylvania.

Pennsylvania Power and Light Company (PP&L). 1993a. Susquehanna Steam Electric Station - Evaluation of Impact on Equipment Due to Higher Room Temperature Due to Loss of Spent Fuel Pool Cooling With LOCA and LOOP. SEA-EE-550, Pennsylvania Power and Light Company, Berwick, Pennsylvania.

Pennsylvania Power and Light Company (PP&L). 1993d. Loss of Fuel Pool Cooling/Coolant Inventory - Susquehanna Off-Normal Operating Procedure. ON-135(235)-001, Rev. 13, Pennsylvania Power and Light Company, Berwick, Pennsylvania.

Pennsylvania Power and Light Company (PP&L). 1993e. Technical Support Coordinator: Emergency Plan-Position Specific Procedure. EP-PS-102, Rev. 7, Pennsylvania Power and Light Company, Berwick, Pennsylvania.

Portland General Electric. 1992. Individual Plant Examination Report for the Trojan Nuclear Power Plant in Response to Generic Letter 88-20. Portland General Electric Company, Portland, Oregon.

Russel, K. D. et al. 1991. Integrated Reliability and Risk Analysis System (IRRAS). Idaho National Laboratory, Idaho Falls, Idaho.

Sailor, V. L. et al. 1987. Severe Accidents in Spent Fuel Pools In Support of Generic Safety Issue 82. NUREG/CR-4982. Brookhaven National Laboratory ora ory, Upton, New York.

5.2

Sattison, H. B. et al. 1990. Analysis of Core Damage Frequency: Zion, Unit I Internal Events. NUREG/CR-4550, Volume 7, Rev. 1, Idaho National Engineering Laboratory, Idaho Falls, Idaho.

Sobel, P. 1993. Revised Livermore Seismic Hazard Estimates for 69 Nuclear Power Sites East of the Rocky Hountains. NUREG/CR-1488, Nuclear Regulatory Commission, Washington, D.C.

Swain, A. D. 1987. Accident Sequence Evaluation ProgramNHuman Reliability Analysis Procedures Guide. NUREG/CR-4772, Nuclear Regulatory Commission, Washington, D.C.

.U.S. Nuclear Regulatory Commission (NRC). 1985. Probabilistic Safety Analysis Procedures Guide. NUREG/CR-2815, Rev. 1, U.S. Nuclear Regulatory Commission, Washington, D.C.

U.S. Nuclear Regulatory Commission (NRC). 1988. Individual Plant Examination: Submittal Guidance. NUREG-1335, U.S. Nuclear Regulatory Commission, Washington, D.C.

U.S. Nuclear Regulatory Commission (NRC). 1989. Severe Accident Risks: An Assessment for Five U.S. Nuclear Power Plants. NUREG-1150, U.S. Nuclear Regulatory Commission, Washington, D.C.

Virginia Electric and Power Company. 1991. Probabilistic Risk Assessment for the Individual Plant Examination Final Report, Surry Units 1 and 2. Virginia Electric and Power Company, Richmond, Virginia.

Wheeler, T. A. et al. 1989. Analysis of Core Damage Frequency from Internal Events: Expert Judgment Elicitation. NUREG/CR-4550, Volume 2, Sandia National Laboratories, Albuquerque, New Hexico.

Washington Public Power Supply System. 1992. Individual Plant Examination Washington Nuclear Plant 2. Washington Public Power Supply System 5.3

APPENDIX A CASE DETEfNINATION

Appendix A Case Determination This evaluation covers all operating modes for the Units. At different times during operating and shutdown conditions distinct initial conditions and success criteria exist. Separate evaluations (referred to as Cases) of representative conditions were performed to ensure adequate coverage of these separate conditions and criter'ia. Selection of'the Cases was based on the different decay heat levels present in the Spent Fuel Pools (SFP), on the available capacity to remove this heat via the Spent Fuel Pool Cooling System (SFPC), availability of RHR, and the plant operating condition.

.Appendix A Case Determination 1.0 OVERVIEW Selection of the Cases was based on the different decay heat levels present in the Spent Fuel Pools (SFP), on the available capacity to remove this heat via the Spent Fuel Pool Cooling System (SFPC),

availability of RHR, and the plant operating condition. The Cases studied are:

Table A.I Analysis Cases for As-Found Condition Unit 2 Unit 1 All Cases Case 1 Case 2 Case 3 Case 4 Case 5 Plant Condition 0 eratin 0 eratin Shutdown Shutdown Sh'utdown Shutdown Duration (normalized to 1 year) 8768 6368 800 960 320 320 (hrs) f Pumps initially running (SFP

<<115 F t P s Re uired (SFP <200 F)

SFPC Availabilit Yes Yes Yes No Yes Yes RHR Availability (f Loops) 0-8 Days 1-17 Da s Time-to-Doll (hrs) >>50 ~50 i50 i25 i25 15 - 25 2.0 SUCCESS CRITERIA Success for this evaluation is based on maintaining the pools below an excessive steaming condition, not on maintaining the SFPs below the administrative and technical specification limits of 115'F and 125'F.

if It is assumed that the pool is not transferring heat to the atmosphere through boiling mechanisms, then an excessive amount of .heat will not be transferred. Radiative and evaporative losses off the surface of the pool are expected to be relatively small.. The Susquehanna SFP mini-PRA (SA-TSY-001) assumed an excessive steaming condition existed when SFP temperature reached 200'F. When the pools are not cross-connected via the Cask Storage Pit (CSP) this is an adequate assumption. However,, for cross-connected conditions, all cooling could come from either pool. In this latter condition, it is assumed that maintaining the pool being actively cooled below 170'F is adequate to ensure the second pool does not experience excessive steaming.

A.2

Appendix' Case Determination 3.0 SFPC HEAT EXCHANGERS 3.1 SFPC Heat Exchan er Desi n From FSAR Table 9. 1-1 the fuel pool heat exchangers are designed to remove 4.4 HBTU/hr at 125'F shell side temperature (SFP side) and 95'F tube side temperature (SWS.side). Specifically:

Tp 125'F Design temperature of the SFP outlet (heat exchanger inlet)

Tp 110'F Design temperature of the SFP inlet (heat exchanger outlet)

Ts 104'F Design temperature of the SWS outlet (heat 0

exchanger outlet)

Ts 95'F Design temperature of the SWS inlet (heat 1

exchanger inlet) msf 296000 lb/hr Design mass flow rate for the SFP side of the heat exchanger m

496000 lb/hr Design mass flow rate for the SWS side of the heat exchanger 4.4 HBTU/hr Design heat load on the heat exchanger presign under the above conditions Using the following standard counterflow heat exchanger relationships:

(Tp,-Ts) -(Tp,-Ts,)

(Tp,-Ts) (A.1)

Ts,)

(Tp, Qh, = UAFxhT~ (A.2) and substituting in the above values gives:

UAF ~ 2.47x10 BTU/hr'F This UAF is similar to the UAF implied by the predicted values in PPEL calculation H-FPC-013. Predicted heat duties using this UAF were verified to give slightly more conservative values (3% -

5%)

than those presented in the table on page 14 of 84 of H-FPC-013.

A.3

Appendix A Case Determination 3.2 Predicted SFPC Heat Exchan er Perfonnance Using a constant UAF, the equations and values from above, and the following additional relationships:

Q~ 'l~ Gp (TpO Tpl)

(A.3)

Q~ = m~cp(TSO-TS (A.4) allows the heat transfer across the SFP heat exchangers given the SMS inlet temperature and SFP temperature (SFP Outlet Temperature) to be predicted (See Figure A. 1).

300E~ 35 oe a5

.-55 2.00EM

-.75

95 85 SWS Inlet Temperature g 1.50E~

E 1 00E~

5.00EK6 R I 8 ~ 8 I 8 5 8 I 8 g 5FP Outlet Temperature (F)

Figure A.l Susquehanna Heat Exchanger Performance The Figure A.l results are for a single pump/heat exchanger.

Multiple pump/heat exchangers will be assumed to remove multiples of the single pump/heat exchanger values. This assumption is based on Susquehanna procedure OP-135-001 that directs the flow rates for multiple pumps be adjusted to be multiples of 600 gpm (i.e., 1 pump/heat exchanger, m f - 600 gpm; 2 pump/heat A.4

Appendix A Case Determination exchanger, m f 1200 gpm; and 3 pump/heat exchanger, m f 1800 gpm).

3.3 SFPC 0 erational Restraints a 0 Conversations with PPtIL indicate that they will not offload fuel into the pool until two requirements can be met:

1. Time-to-boil is more than 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months , and

2. Total heat load. is within the capacity of the available pump/heat exchangers.

b. PP8L has indicated that in the past, the first requirement, while in the FSAR, was not necessarily proceduralized and conditions may have existed early in some outages where time-to-boil times could have been as low as 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months .

Conditions never existed where time-to-boil was less than 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months for greater than 10 days.

3.4 SFP Confi urations:

The following pool configurations (activities) and associated masses of water are assumed to exist during an outage:

Table A.II SSES SFP Activities Activit Descri tion Ul. Mell, Drypit 8 7,084,213 Cattleshute All Connected 10.697.928 Ul. U2 8 CSP 6.622.057 Sin le Isolated Pool 3.008.341 4.0 DECAY HEAT The SFPC system is designed to maintain the fuel pool water temperature below 125'F at a maximum Normal Heat Load (HNHL). The NNHL is based upon filling the pool with 2840 fuel assemblies from normal refueling discharges and 184 fuel assemblies are offloaded from the active core within 160 hours0.00185 days 0.0444 hours 2.645503e-4 weeks 6.088e-5 months after shutdown (FSAR Table 9. 1-2b). In the FSAR, full core offloads are considered Emergency Heat Load (EHL) conditions which generally credits the RHR system for fuel pool cooling. Generally the RHR system is assumed to be available for fuel pool cooling under EHL conditions. The RHR cooling system using one pump and one heat exchanger can maintain the fuel pool water temperature at or below 125'F with or without assistance from the SFPC system. EHL is defined as a fuel core offload 250 hours0.00289 days 0.0694 hours 4.133598e-4 weeks 9.5125e-5 months after shutdown following a typical fuel A.5

Appendix A Case Determination cycle discharge schedule. The model was built on review of previous outages that indicate full core offloads are normally conducted with decay heat loads in excess of the NNHL, but less than the EHL (requirement for total heat load is within the capacity of the'SFPC System (See 3.3.a.2)). These conditions have been acceptable because of lower than design basis SWS inlet temperatures and corresponding increased SFPC system capacity. This evaluation is based on information from the recent Spring 1994 outage (SSES U26RIO) with some modifications to provide generic coverage of other previous outages. SSES U26RIO information as provided by PP8L:

Table A. III SSES Outage U26RIO Information Oays Acthv1ty HBTU/hr T to 8 fhr) 3008341 2.91 98.21 15 3008341 2.91 98.21 15 7084213 25.12 26. 79 16 7084213 24.46 27. 51 16 10697928 27.37 37.13 19 10697928 25.68 39.58 20 10697928 25.19 40.35 21 10697928 24.73 41.10 22 10697928 24.31 41.81 22 6622057 24.31 25.88 32 6622057 21.04 29.90 36 6622057 20.08 31.33 36 10697928 20.08 50.61 38 10697928 19.65 51.72 38 7084213 16.73 40.23 52 7084213 14.43 46.64 55 7084213 14.05 47.90 55 3008341 5.10 56.04 63 3008341 4.88 58.56 Note that the heat load of 25. 12 NBTU/hr present on day 15 is beyond the capacity of the SFPC System when it is operating at 'its design based SWS Inlet and SFP temperatures. However, it can be handled by 3 SFPC pump/heat exchangers if SFP temperatures are maintained at the administrative limit of 115'F, and SWS Inlet Temperature is at or below 55'F. An SWS Inlet temperature this low is a reasonable expectation considering the early spring time-frame of the outage. Under these SWS and SFP temperatures, 2 SFPC pump/heat exchangers can carry the expected

'load in the shutdown Unit's SFP by day 35.

A.6

Appendix A Case Determination For the purposes of this evaluation a slightly lower initial heat load and higher SWS Inlet Temperature will be assumed. This is done to account for the SFPC operational restraint noted in Section 3.3.b, where the time-to-boil could be as low as 15 hours. In the past when only 15 .

hours existed before onset of boiling, it is unlikely this occurred during Activity 1, as 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months implies a heat load of 44.9 NBTU/hr.

Even at an SWS Inlet temperature of 35'F, the total heat load that could have been removed would be 35.4 MBTU/hr, which correlates to 19 hours2.199074e-4 days 0.00528 hours 3.141534e-5 weeks 7.2295e-6 months to boiling. The most likely scenario is an offload in Activity 1 followed by entry into Activity 4. Activity 4 with a time-to-boil of. 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months implies a heat load of 19.1 HBTU/hr. Using the general shape of the SSES U26RIO Outage decay curves, assuming that the short time-to-boil condition exist for 10 days, and that 2 SFPC pump/heat exchangers can remove the heat load by day 35, results in there being a 19. 1 NBTU/hr heat load on day 25, a 23.5 NBTU/hr heat load on day 15 and an SWS Inlet Temperature of about 65'F.

Higher and lower initial heat loads are bounded by this evaluation as long as the requirements outlined in Section 3.3 are met. Initial heat load is matched to a maximum corresponding SWS Inlet temperature to maintain less than 115'F in the SFP, which results in similar times to transitions between required pump/heat exchangers.

'5.0 PLANT OPERATING CONDITIONS Day 0 Plant Shutdown, RHR in Shutdown cooling, SFP being cooled by 1 pump/heat exchanger combination.

Day 8 One loop of RHR unavailable for maintenance. Other train still providing Shutdown cooling.

Day 15 Fuel offload complete. Three pump/heat exchangers required to cool SFP. Both loops of RHR available.

Day 25 SFP isolated from reactor cavity and other SFP (Activity 4).

Day 35 Activity 4 exited (by cross-connecting with other SFP), Heat load has decay to the point that 2 pumps/heat exchangers can handle load. SFPC taken out-of-service for maintenance.

Cooling of SFP is dependent on pumps from other SFP via cross-connect.

Day 65 SFPC restored to service . Fuel reload completed. One pump/heat exchanger can car ry the heat load.

Day 75 Unit restored to power.

SFPC is normally returned to service in as little as 10 days. Hodeling the SFPC out-of-service 1

on Unit I and the SFPC cross-tied is slightly more conservative than modeling the Unit 1 SFPC inservice with the pools not-cross-connected. It was decided to model this period using the former more conservative condition because no apparent adninistrative controls were noted that limit m thee time me the SFPC P s stem is out-system of-service. and the conservatism is small.

A.7

Appendix A Case Determination

6. 0 EVALUATION CASE DETERMINATION Figure A.2 presents a timeline of the Cases to be discussed below that occur during an outage. Case 1 covers all non-outage conditions.

SFP = 200 1 SFPC Pump 2 SFPC 1 SFPC Pumps 1 SFPC Pump SFPR115F 1 SFPC Pump 3 SFPC 2 SFPC Pumps 1 SFPC Pump 25.N 100.N Uel 1 (MBTUih0 Tsu8 75 0) 70.N

>~ 15.N 65.N S 60.N o 55.N E

50.N u 10.N Q

O 45.N 5.00 0.00 15.N 0 5 10 1 20 25 30 40 45 50 55 60 70 75 Outage (0~

Figure A.2 Modeled SSES As-Found Outage Sequence/Conditions 6.1 Unit 2 Modelin a ~ All Cases Because Unit 2 is always assumed to be operating, the number of pumps initially running and the number required to avoid 200'F in the isolated pool will be modeled the same in all Cases.

f Pumps initially running in Unit 2 m 1. The normal steady state decay heat load is removable even at the design SWS Inlet Temperature of 95'F. However, higher decay heat values would be expected just after exiting an outage that would require more than 1 pump/heat exchanger at the design temperature. This design basis need for 2 pumps/heat excha'ngers will not be modeled as actual SWS Inlet A.8

Appendix A Case Determination temperatures have been low enough to allow 1 pump/heat exchanger to remove the load. SWS Inlet Temperatures have always been low enough at the beginning of the outage to allow 3 pumps/heat exchangers to remove the full heat load.

It is expected SWS temperatures would have similar values at the end of the outage, thus allowing removal of the slightly raised decay heat in the pool at plant startup using a single pump/heat exchanger.

0 Pumps required to avoid 200 F in Unit 2 ~ 1. A single pump/heat exchanger can remove the required heat load at 200'F even assuming an immediate startup after fuel reload in the last outage and using the design SWS Inlet Temperature.

RHR Availability. Since Unit 2 is assumed to be operating, its RHR is assumed to be in an ECCS lineup.

Duration. Eighteen months (one Unit is always operating-the model assumes it is Unit 2). Normalized to 1 year >>

8768 hours0.101 days 2.436 hours 0.0145 weeks 0.00334 months .

Time-to-Boil. >50 hours. Assuming the 5.1 MBTU/hr and the minimum pool configuration (isolated pool) results in a time-to-boil of 56 hours6.481481e-4 days 0.0156 hours 9.259259e-5 weeks 2.1308e-5 months .

6.2 Unit 1 Hodelin Unit 1 can be in either an operating or outage condition. To allow for the different pool and pool cooling support configurations five different Cases will be examined which bound expected conditions. A sequential discussions of these Cases follows. Note that the discussion order does not follow the numbered order of the Cases.

Case 1 - Unit 1 Operating, 1 pump/heat exchanger required.

This Case is identical to the normal modeling for Unit 2, with the exception of duration.

Entry/Exit: Entry and exit to/from this Case is via Case 2 Duration: Exit from this condition occurs when the unit is shutdown. All outages are 1's operating time is then modeled to occur on Unit l. Unit 18 months minus two 75 day outages. Normalized to 1 year 6368 hours0.0737 days 1.769 hours 0.0105 weeks 0.00242 months .

Appendix A Case Determination Case 2 - Unit 1 Shutdown, 1 pump/heat exchanger required.

I Entry/Exit: Entry to Case 2 occurs two ways: 1) as an exit from Case 3, and 2) after Unit shutdown as an exit from Case

l. Exit is to Case 1 or Case 4.

0 Pumps initially running in Unit 1 I. When initially shutdown with the core in the reactor vessel, expected decay heat loads are bounded by the Case 1 analysis and easily removed with 1 pump/heat exchanger regardless of SWS Inlet Temperature (within design parameters). For the condition

.when entry is from Case 3, decay heat may be above that removable with 1 pump/heat exchanger at the SWS Inlet Temperature design value (95'F). However, it is expected that SWS Inlet Temperature will be similar to that which allowed offloading. If the decay heat can be removed with 3 pump/heat exchangers at SFP Temperature 115'F, then it is expected the remaining decay heat after refueling can be removed by 1 pump/heat exchanger.

0 Pumps required to avoid 200'F in Unit 1 l. A single

'ump/heat exchanger can remove the required heat load at 200'F, even assuming a full pool with a third of the core recently offloaded and the design SWS Inlet Temperature. I RHR Availability: Since fuel is assumed to be in the reactor vessel, one loop of Unit 1's RHR is assumed to be in S/D cooling. Maintenance outages of RHR loops is allowed and is modeled as lasting for 8 days during this Case.

Duration: Twenty-five days. Exit from this condition occurs when fuel is offloaded (day 15) to the SFP or when the Unit is restarted. Case exists from day 0 to day 15, and from day 65 to 75. Normalized to 1 year and doubled for two outages 800 hours0.00926 days 0.222 hours 0.00132 weeks 3.044e-4 months .

Time-to-Boil: >50 hours.

Case 4 - 3 pumps/heat exchangers required, Unit 1 S/D-Normal time-to-boil.

Entry/Exit: Entry to Case 4 is from Case 2 when the fuel is offloaded to the SFP. Exit is to Case 5, when the Unit 1 SFP is isolated, resulting in a time-to-boil less than 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months .

8 Pumps initially running in Unit 1 ~ 3. Per the requirement expressed in Section 3.3.a.2, fuel is not offloaded until the decay heat is within the capacity of the I

A.10

Appendix A Case Determination SFPC System. It is expected offload occurs when this condition is reached.

0 Pumps required to avoid 200'F in Unit 1 2. For all examined SWS Inlet Temperatures, if the decay heat can be removed with 3 pumps/heat exchangers at SFP Temperature-115'F, then it can also be removed by 2 pumps/heat exchangers at an SFP temperature of 200'F.

RHR Availability. Since no fuel is assumed to be in the reactor vessel, both loops of Unit 1's RHR are assumed not to be in S/D cooling.

Duration. Ten days. Assuming the decay heat and SWS inlet temperature are such to just allow offload at the beginning of this condition, it is expected the decay heat decreases to within the capacity of 2 pumps/heat exchangers in 20 days. However, 10 of these days are spent in Case 5.

Normalized to 1 year and doubled for two outages 320 hours0.0037 days 0.0889 hours 5.291005e-4 weeks 1.2176e-4 months .

Time-to-Boil. >25 hours.

d. Case 5 - Unit 1 Shutdown, 3 pumps/heat exchangers required, Short time-to-boil.

This was a specifically requested portion of the evaluation.

The Case covers conditions where boiling could have occurred in as little as 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months . PP&L further stipulated theses conditions never existed for greater than 10 days.

Entry/Exit: Entry is from Case 4 when Unit 1's SFP is isolated. Exit is to Case 3, when decay heat is removable with 2 pumps/heat exchangers, and the pool is unisolated.

f Pumps initially running in Unit 1'~ 3. See discussions above.

0 Pumps required to avoid 200'F in Unit 1 2. At an SFP temperature of 200'F, heat load of 19. 1 NBTU/hr, and SWS inlet temperature of 65'F, a single pump/heat exchanger combination can marginally remove the .heat load. To account for inaccuracies, 2 pumps/heat exchangers will be modeled as required.

RHR Availability. Since no fuel is assumed to be in the reactor vessel, both loops of Unit 1's RHR are assumed not to be in S/D cooling.

Appendix A Case Determination Duration. Ten days. PP&L stipulated that this condition has never existed for more than 10 days. Case exists from day 15 to day 25. Normalized to I year and doubled for two outages 320 hours0.0037 days 0.0889 hours 5.291005e-4 weeks 1.2176e-4 months .

Time-to-Boil. 15-25 hours.

Case 3 - 2 pumps/heat exchangers required, Unit I S/D Entry/Exit: Entry is from Case 5 when decay heat is removable with 2 pumps/heat exchangers, and the pool is Exit is to Case 2 when the fuel is reloaded 'nisolated.

into the reactor vessel.

f Pumps initially running in Unit I 0. For this Case, the cooling will have to come from Unit 2, as the SFPC system is assumed to out-of-service for maintenance for the entire duration of the Case. Unit 2 will require 2 pumps to remove the Unit I heat load and I pump to remove its own heat load.

This is based on assuming the decay heat and SWS inlet temperature are such to just allow offload at the beginning of this Case 4. It is thus expected the decay heat decreases to within the capacity of 2 pump/heat exchangers in 20 days.

0 Pumps required to avoid 200'F in Unit I 1. The pump will have to come from Unit 2, but only I pump is required.

This is based on the fact that for all examined SWS Inlet Temperatures, if the decay heat can be removed with 2 pump/heat exchangers at SFP Temperature ll5'F, then it can also be removed by I pump/heat exchangers at an SFP temperature of 200'F.

RHR Availability. Discussion with NRC Staff and SSES personnel indicate RHR is often taken out-of-service for maintenance at the beginning of this Case, and is not completely restored for around 10 days. For modeling purposes RHR is modeled as unavailable during all of Case 3.

Duration. Thirty days. Exit from this condition occurs when fuel is reloaded. It is unlikely that an outage would last long enough for decay heat to be removable with 1 pump/heat exchanger. Indications from PP&L are that this usually occurs around day 55 (duration 20 days} of an outage. As there are no controls requiring this, and this Case is more limiting than'the next Case, the expected duration of 20 days is extended to 30. Case exists from day 35 to day 65. Normalized to I year and doubled for two outages >> 960 hours0.0111 days 0.267 hours 0.00159 weeks 3.6528e-4 months .

Appendix A Case Determination Time-to-Boil. >25 hours. Figure A.2 shows the time-to-boil to always be >50 hours. However, the more limiting condition of time-to-boil being >25 hours was chosen to reflect conditions were the cross-connection is not maintained and/or early entry occurs into Case 3 (with resulting higher decay heat levels). This latter condition',

can occur if the operating unit's SFP decay heat is low enough to allow the total heat load to be removed using the operating unit's SFPC System before the shutdown unit's SFP heat load has lowered to within the capacity of two pump/heat exchangers.

6.3 Cross-Connected Pum Re uirements For both the number of pumps initially running and the number required to prevent excessive boiling, the assumed value will be the sum of the Unit I and Unit 2 values discussed above. The initially,running should be fairly accurate as it is expected that even in a cross-connected condition the operators will maintain cooling to both units. In the case of the number required to prevent excessive boiling this gives very conservative values, even when a lower maximum SFP Temperature (170'F) is implemented.

Generally, one fewer pump than that predicted by the above method is all that is required. However, this conservatism allows for simpler modeling, and allows for the uncertainties in how well cooling one pool will affect the other cross-connected pool.

A.13

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APPENDIX B FAULT TREES (Hardware Failure Rates, Fault Tree Basic Events, Common Cause, Simplified PS IOs)

Appendix B Fault Trees This appendix contains the information describing the methods used to generate the hardware failure rates used in the evaluation. Information is provided

,concerning basic events selection and common cause evaluation. This appendix also includes the graphical representation of the modeled system upon which the fault tree are based.

a) Hardware failure rates. A table which list the predicted hardware failure rates is provided. These values were obtained from analysis of, the fault trees using the basic and common cause events discussed elsewhere in the appendix.

b) Component Failure Data. A table which list the component type and failure mechanism, values from a variety of sources, the selected value used in this evaluation, and the justification for using the selected value.

c) Basic Event Selection. A table is provided to explain how the Component Failure Data was incorporated into the Basic Events used in Fault Trees for this evaluation.

d) Common Cause. A short document is provided that gives description of the methods used to generate the common cause failure probabilities, as well as tables summarizing the data input,.

selected sources, and final values.

e) Hodeled Systems. The indicated systems were modeled as fault trees using the IRRAS PRA computer code.

Hardware Failure Rate Appendix B Fault Trees Table B.I, SSES As-Found Harware'Failure Rates Initratrng Event isolated isolated mbined Isolated Isolated mbined oss tie U1 SFPC U2 SFPC SFPC U1 RHR U2 RHR RHR Restart Restart Restart System System System Re cove Recove Re cove Lass ot SFPC N A 3.41E44 843 E43 7.97E45 9.82E42 3.40E44 3ME41 NA 3.05E43 9.82E42 NA 8.53E43 N A 2.04E44 8.53E43 7 9?E45 9.82E42 2.04E44 8.53E43 N A 7.97E45 9.82E42 LOOP 3.96E44 3.S6E44 8.99E48 9.34E43 8.73E45 S.B2E42 3.96E44 3.96E44 8.99E48 2.5?E41 305E43 982E42 4.33E44 N A 8.53E43 O.OOE+00 4.33E44 3.96E44 5.64E46 8.53E43 9.34E43 7.9?E45 9.82E42 4.33E44 3.96E44 5.64E46 8.53E43 9.34E43 7.97E45 9.82E42 Extended Loop 3.96E44 3.96E44 8.99E48 9.34 43 9.34E43 8.?3E45 9.82E42 3.96E44 3.96E44 8.99E48 3.26E4'l 9.34E43 3 05E43 9 82E42 NA 4.33E44 N A NA 8.53E43 N A 4.33E44 3.96E44 5.64E46 8$ 3E43 9.34E43 7.9?E45 9.82E42 4.33E44 3.96E44 5.64E46 8.53E43 9.34E43 7.97E45 9.82E42 SBO 3.96E44 3.96E44 8.99E48 9.34E43 9.34E43 8.73E45 9.82E42 3.96E44 3.96E44 8.99E48 3.26E41 9.34E43 3.05E43 9.82E42 4.33E44 N A N A 8.53E43 O.OOE+00 4.33E44 3.96E44 5.64E46 8.53E43 9.34E43 7.9?E45 9.82E42 4.33E44 3.96E44 5.64E48 8.53E43 9.34E43 7.97E45 9.82E42 LOCA 3.96E44 N A 8.99E48 NA 9.34E43 9.82E42 3.96E44 N A 8.99E48 N A NA 9.34E43 9.82E42 4.33E44 N A NA N A 4.33E44 N A NA 9.34E43 9.82E42 4ME44 N A 5.64E46 N A 9.34E43 9.82E42 Flood 3.96E44 N A 8.99E48 8.53E43 N A 7.9?E45 9.82E42 3.96E44 N A 8.99E48 3.26E41 NA 3.05E43 9.82E42 NA 4.33E44 N A NA 8.53E43 N A 4.33 44 N A 5.64E46 8.53E43 7.9?E45 9.82E42 4.33E44 N A 5.64E46 8.53E43 N A 7.97E45 9.82E42 Loss of WS 3.96E44 N A 8.99E48 8.53E43 N A 7.9?E45 9.82E42 3.96E44 N A 8.99E48 326 E41 NA 3.05E43 g.82E42 NA 4.33E44 N A NA 8.53E43 4.33E44 N A 5.64E46 8.53E43 7.97E45 9.82E42 4.33E44 N A 5.64E46 8.53E43 N A 7,9?E45 '.82E42 Pipe Break 3.96E44 8.99E48 8.53E43 N A 7.97E45 9.82f 42 3.96E44 N A B.S9E48 3.26E41 N A 3.05E43 9.82E42 NA N A 4.33E44 N A 8.53E43 N A 4.33E44 N A 5.64E46 8.53E43 7.97E45 9.82E42 4.33E44 N A 5.64E46 8.53E43 NA 7.g7E45 9.82E42 Seismic N A N A N A 9.34E43 9.34E43 NA N A N A 3.26E41 9,34E43 N A N A N A N A 8.53E43 N A N A N A N A 8.53E43 N A N A N A N A 8.53E43 9.34E43 NA L w/L P 3.96E44 3.96E44 8.99E48 N A 9.34E43 9.43E43 9.82E42 3.96E44 3.96E44 8.99E48 N A 9.34E43 9.43E43 9.82E42 N A 4.33E44 N A N A N A 4.33E44 3.96E44 5.64E46 N A 9.34E43 9.43E43 9.82E42 4.33E44 3.96E44 5.64E46 N A 9.34E43 9.43E43 9.82E42 B.2

Hardware Failure Rate Appendix B Fault Trees Table B.II, SSES As-Fixed Hardwar e Failure Rates Initiating ent IAbined IAblned SFPG RHR Restart System Re cove Loss ot F 7.97 45 3.05 43 8.99 ~ '.73 ~

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ended Loop 8.99 48 8.73 45 8.99 ~ 3.05 ~

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B.3

Component Failure Data Appendix B Fault Trees Basic Event Source Soutce Range Fn ) ¹3 ¹4 ¹5 ¹6 Point (Ref) (Raf) (Rel) (Rel) (Estimate)

Valve-Manual 1E-7/h 3E-9/h 6E4/h 3E-9/h -1E- Used the most Fre. 7/h conservative value Rugged or fouled from the NRG sources (NUAEG/CR-NUREG/CR. NUClARR ORNL 1E-7/h 4550).

4550 (Ref. 1) (Ref. 2) Reliability Data (Ref. 6)

Valve. Manual 1E-7/h 6E4/h 6E4/h- Used the available Fre. 1.1E-7/h NRG value.

Leak or rupture (NUClARA)

NUCLARR Shoreham OANL (Ref. 2) PRA (Ref. 9) Reliability Data (Ref. 6)

Valve-Manual 8EA/d 8EP/d Used the available Fre. NRC value.

Unavailable due (NUREG/CM550) to maintenance NUAEG/GR. 8EQ/d 4550 (Ref. 1)

SEA/d 1&I/d 6.32E-5/d 1'/d 6EQ/d fEQ/d 6.32E-5/d- Used the available Fre. 6EQ/d NRG value.

Failure to dose (NUCLARA) on demand NUCLARR Shoreham IEEE 500 Calvatt Cliffs ORNL Susquehanna 5EP/d (Ref. 2) PAA (Raf. 9) (Aaf. 7) lREP (Ref. 5) Reliability IPE PRA Data (Ref. 6) (Ref. 8)

B.4

Component Failure Oata Appendix B Fault Trees Source Source Range

¹1 ¹2 ¹3 ¹4 ¹8 (Rei) (Rel) (Ref) (Rel) (Ret) (Estkn ate)

Valve.Manual 1&I/d 6E4I/h 2.3E4I/O- No applicable NRC Fre. 2.3E-T/h Value. Used the IEEE Failure to remain or IEP/d 500 value.

dosed NUREG/CR- IEEE SQQ ORNL 2.3'/h 4550 (Ref. 1) (Rel. 7) Reliability Data (Ref. 6)

Valve-Manual 1'/d 5&l/d 1'/d 6,32E-S/d 1E-4/d 6'/d 6.32E-5/d- Used the value from Fre. 6'/d the preferred NRC Failure to open . source. (NUREG/CR-on demand 4550).

NUREG/CR. NUClARR Susquehanna IEEE 500 Calvert Gifts OANL 1'/d 4550 (Ref. 1) (Ref. 2) IPE PRA (Aef. 7) IAEP (Ref. 5) Reliability (Ref. 8) Data (Ref. 6)

Valve. Manual 1.25'/d 3.4'/h 6&I/h 3.7'/h 2.3E4/h- No ap'pgcable NRC Fre. 2.3E-7/h Value; used Oconee Failure to remain or 1.25'/d PRA.

open Shoreham Oconee PRA IEEE SQQ OANL ALWR 3.4E4I/h PRA (Ref. 9) N SAC/60 (Aef. 7) Reliability Reliability SENTI/h (Ref. 10) Data (Ref. 6) Data (Ref. 3)

Valve-Check SKI/h 5E-9/h Used the available Fre. NRC value Rugged or fouled (NUCLARR).

NUCLARR (Ref. 2)

Valve-Check 1E-7/h 3.5E4/h 1.07E4I/h 5E-7/h 6E-T/h 1E-7/h 3.5E- Used the value from Fre. 6/h the preferred NRC Leak or rupture source (NUREG/CR-4550).

NUREG/CR- NUClAAR Shoreham Calvert Qifls ALWR 1E-7/h 4550 (Ref. 1) (Ref. 2) PRA (Ref. 9) IREP (Ref. 5) Reliability Data (Ref. 3)

B.5

Component Failure Data Appendix B Fault Trees Basic Event Source Source Range (7n ) ¹2 ¹4 ¹8 (Rel) (Ref) 'Ref) (Ref) (Essm ate)

Valve-Check 2E4/h 1 '/d IEO/d IE4/d 9.6E-5/d 2ER/d 9/6E-5/d- Used the value from Fre. 2'/d the preferred NRC Failure to dose or 2E4/h source (NUREG/CR-on demand 4550). In addition the PSA NUREG/CR. NUCLARR Susquehanna IEEE 500 ALWR 1 '/d NUREG/CR4550 and Ref. Procedure 45SO(Ref. I) (Ref. 2) IPE PRA (Ref. 7) Reliability NUCIARR values guide (Ref. 4) (Ref. 8) Data (Ref. 3) were the same.

Valve-Check 1E-7/h 3.5E4/h 1.6E41/h 1E-7/h- Used the value from Fre. 3SE4/h the preferred NRC Failure to remain source (NUREG/CR-dosed 2815).

PSA NUCIARR Shoreham IEEE Soo 1E-7/h Procedure (Ref, 2) PRA (Ref. 9) (Ref. 7) guide (Ref. 4)

Valve. Check 2E.7/h 1E</d SE-5/d 1.1EQ/d 9.8E-5/d 2&I/d SE-5/d - 2E- Used the Fre. 4/d consenrative value Failure to open or 2E-7/h from Susquehanna on demand IPE PRA.

PSA NUREG/CR- NUCIARR Susquehanna IEEE 500 ALWR 1.1'/d Procedure 4550 (Ref. 1) (Ref. 2) IPE PRA (Ref. 7) Reliability guide (Ref. 4) (Ref. 8) Data (Ref. 3)

Valve. Check 23E-7/h 2E-7/h 2E-7/h - 2.08- No applicable NRC Fre. 6/h value. Used the value Failure to remain from the Oconee open PRA.

Oconee PRA IEEE 500 ALWR 23E-7/h N SAC/60 (Ref. 7) Reliability (Ref. 10) Data (Ref. 3)

Pump-Motor 3'/d Used the available Fre. NRC value Leak or rupture (NUClARR).

NUCLARR 3E6/h (Ref. 2)

B.6

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Component Failure Data Appendix B Fault Trees Basic Event Source Range

¹1 ¹2 ¹4 ¹5 (Estimate)

(Type)

(Ret) (Rel) (Ret) (Rei)

Heat Exchanger 3E</h 3E-5/h Used the available (Shell) Fre. NRC Value (NUREG/CR4550).

Unavailable due to malnlenance NUREG/CR- 3'/h 4550 (Ref. 1)

Heat Exchanger 5.7'/h 3E-?/h 3.39'/h 3E-7/h- Used the available (Tube) Fre. 5.7'/h NRC value (NUREG/CR4550).

Rugged or fouled NUREG/CR- NUClARR IEEE 500 ALWR 5.7E4I/h 4550 (Ref. 1) (Ref. 2) (Ref. 7) Reliability Data (Ref. 3)

Heat Exchanger 3E.9/h 3E4/h 1 '/h 5.7E41/h 3.39'/h 1E4I/h 3E-9/h- Used the most (Tube) Fre. 5.7E4I/h conservative value from the NRC Leak or rupture sources (NUREG/CR-PSA NUREG/CR- NUClARR Shoreharn IEEE 500 ALWR 4550).

Procedure 4550 (Ref. 1) (Ref. 2) PRA (Ref. 9) (Ref. 7) Reliability guide (Ref. 4) Data (Ref. 3)

Heat Exchanger 3E-5/h Used the available (Tube) Fre. NRC Value (NUREG/CR4550).

Unavailable due to maintenance NUREG/CR- 3E4/h 4550 (Ref. 1)

Transmlttdr- 3'/h 3E4/h 2.1E4I/h 5E4/h 2E-7/h 2.1 E4I/h- Used the value from Pressure Fre. 5E41/h the preferred NRC source (NUREG/CR-Failure to operate 4550). NOTE:

NUREG/CR- NUCLARR Oconee PRA ALWR Susquehanna 3E4/h NUCLARR value was 4550 (Ref. 1) (Ref. 2) N SAC/60 Reliability IPE PRA identical.

(Ref. 10) Data (Ref. 3) (Ref. 8)

B.8

Component Failure Data Appendix B Fault Trees Source &xaee Sxaea Range

¹1 ¹2 ¹3 ¹4 ¹6 Point (Ref) (Ref) (Ref) (Rel) (Ref) (Esffrnate)

Strainer 3E-5/h 3E-5/h SEA/h 3E-S/h 2E4/h 2E4/h- Used the most Fre. 3E-5/h conservative value Plugged or from the NRC Fouled sources. NOTE: PSA PSA NUREG/CR- NUCLARR Calvert Cliff ALWR 3E-5/h and NUClARR values Procedure 4550 (Ref. 1) (Ref. 2) IREP (Ref. 5) Reliability were Identical.

guide (Ref. 4) Data (Ref. 3)

Tank 5E-7/h- 1E-7/h IE-7/h- Used the available Fre. 5E-7/h NRC Value Leak or rupture (NUCLARR).

NUCLARR ALWR SE-7/h (Ref. 2) Reliability Data (Ref. 3)

Passive Safety 3.75'/h 3.75'/h Used the value from Valve Fre. the preferred NRC source (NUREG/CR-Activates/de- 4550). NOTE:

activates Shoreham 3.75E4I/h NUCLARR value was Inadvertently PRA (Ref. 9) Identical.

Room Cooler 1'/h 1E-5/h 1.9E-S 1E-5/h . 5E6/h 1.9E Used the value from Fre. 5E4I/h the preferred NRC Fails to run source (NUREG/CR-4550). NOTE:

NUREG/CR- NUCLARR Oconee PRA Calvert Cliff ALWR NUCLARR value was 4550 (Ref. 1) (Ref. 2) N SAC/60 IREP (R@f. 5) Reliability Identical.

(Ref. 10) Data (Ref. 3)

Room Cooler 1'/h 1E-5/h 1.9E-S 1E-5/h 1.9E-S- Used the value from Fre. 5E4/h the preferred NRC Fails to run source (NUREG/CR-4550). NOTE:

NUREG/CR- NU GLAR Oconee PRA Calvert Cliff ALWR 1E-5/h NUCUIRR value was 4550 (Ref. 1) (Ref. 2) N SAC/60 IREP (RBI. 5) Reliability identical.

(Ref. 10) Data (Ref. 3)

B.9

Component Failure Data Appendix B Fault Trees Sash Event Source Source Range Fyp ) ¹1 ¹2 ¹3 ¹4 ¹5 ¹6 Point (Rel) (Rel) (Rel) (Re) (Ref) (Rel) (Estimate)

Pipe 1.1E4/h 8.59E-9/h 8.59E-9/h- Used the available Fre. 1.1E-8/h NRC Value Leak or rupture (NUCIARR).

NUCtARR Shoreham 1.1'/h (Ref. 2) PRA (Ref. 9)

Relay 3E4/h 4.3E-r/h 3E4/h 5.36B/h- Used the available Fre. 3E4/h NRC Value (PSA).

Short PSA Shoreham Oconee PRA Calvert Cliffs Procedure PRA (Ref. 9) N SAC/60 IREP (Ref. 5) guide (Ref. 4) (Ref. 10)

Relay 3E4I/h 2.68E.7/h 4.3E4/h 3E4/h 2.68E-7/h- Used the available Fre. 4.3'/h NRC Value (PSA).

Open PSA Shoreham .

Oconee PRA Calvert Cliffs 3E4I/h Procedure PRA (Ref. 9) N SAC/60 IREP (Ref. 5) guide (Ref. 4) (Ref. 10)

Relay IE6/h 3EA/d 12EQ/d 2.4'/d 3'/d 1'/d 1'/d - 3E- Used the most Fre. 4/d conservative value Failure to or IE4/h from the NRC actuate/deactlvat sources (NUCLARR).

e on demand PSA NUCLARR Susquehanna Oconee PRA Calvert Cliff ALVIN 3&!/d Procedure (Ref. 2) IPE PRA N SAC/60 IREP (Ref. 5) Reliability guide (Ref. 4) (Ref. 8) (Ref. 10) Data (Ref. 3)

B.10

Component Failure Data Appendix B Fault Trees NOTES: General - The highlighted values Indicate the selected data source to be used.

Some of these references are crossed referenced to each other and to other sources. For example the NUREG/CR4550 (Ref. 1) val ues are sometimes obtained from the Shoreham PRA (Ref. 9) which In tern references NRC LER Data, WASH-1400, and General Bectrlc BWR Data.

convert b e tween h ou rly failure rates and demand References do not always provide the same failure rate basta (I.e., hourly versus demand). The relationship used too conve ure ra es was: D~ (HxT)/2. Generally, lf the value was provided In a format which was not consistent with the parameter of concern (e.g., an hourly rate for a demand failure), then the value was not considered as an option.

in the ALWR (Ref. 3) specific motordrlven pump failures data was given for failure to start and failure to run. The corres ondlnng Iterna rrespon e In thlsta b le are represented as

REFERENCES:

1. Analysis of Core Damage Frequency From Internal Events: (NUREG/CR-1150) Methodology Guldellne, NUREG/CR-4550, Vol. 1, Rev. 1, September 1987.

2. Generic Component Failure Database for Ught Water and Uquld Sodium Reactor PRA's (NUCLARR), EGG-SSRE4875, Februa e ruary 1990.

3. Re'liability Database for ALWR PRA's.

4. Probablflstlc Safety Analysts Procedures Guide, NUREG/CR-2815, August 1985.

5. interim Reliability Eva'luation Program: Analysis of the Calvert Qiffs Unit 1 Nuclear Power Plant, NUREG/CR3511, March 1984.

e. Oak Ridge Nathnal Laboratory In-Rant Rellabiflty Data Systems for Pumps, Valves, and Bectrlcal Power Components, NUREG/CR.2888, NUREG/CR4554. NUREG/CR-IEEE Guide to the Collection and Presentation of Electrical, Bectronlc, Sensing Components, and Mechanical Equipment Reliabilitya a fo Data or Nu cl ear P ower G eneratlng Stations, IEEE Std. 500-1984, December 1983.

8. Susquehanna Steam Electric Station Individual Plant Evaluation, December 1991.

9. Shoreham Nuclear Power Station Probabilistic Risk Assessment, June 1983.

10. Oconee PRIL A Probabllistic Risk Assessment of Oconee Unit 3, EPRI Report NSAC/60, June 1984

Basic Event Values/Information Appendix B Fault Trees Table B.IV Com onen1T e Failure Descri tion Value Basis Com onent Failure Data unless otherwise noted Check Valve Fails to o en on demand 1.00E44 d Check Valve Failure 3.30E47 h Leakorru ture and failure to remaino en Crane- Falls to release gate 1.00E44 d Mechanical dev/ce ding on demand. Smflar to valve (manual or check).

Crane (normal) Falls to function 6.00E43 d Motor failures for moving crane and powering wench. Motor failures assumed to occur at same rate as Motor o crated valves or um s.

Crane (Single Faflute Falls to function 3.60E45 d Motor failures for moving crane and powerlng wench. Assumes dual motors available for both functions. Motor Proof) failures assumed to occur at same rate as Motor o crated valves or umps.

Cross-tie Support Air System Falls to Shut 1.00E46 d Screening vaiue based on multiple component supports.

Off or Deflate Cross-tie Su rt Loss of Power 1.00E45 h LOOP combined with a mean value for loss of load centers from the Su uehanna mini.PRA Gate Falls to retnove 1.00E44 d Modeled as manual valve failure to o n.

Heat Exchanger Failure 6.70E46 h Heat Exchanger Loss of SWS to HX 1.00E45 h Loss of SW to heat exchanger and leak or rupture and plugging. This equals about 9E4/h. Rounded up for conservatism.

Heat Exchanger Unavailable due to 9.00E45 h 3 times the normal rate of 9E-5/h to reflect modeling technique (only one of three pumps Is considered for test maintenance OOS due to maintenance)

Manual Valve Falls to open on demand 1.00E44 d Manual Valve Falls to remain dosed 2.30E48 h Manual Valve Falls to remain o en 1.14E47 h Combination of lug or foul and fails to temaln o en Manual Valve Failure, 2.10E47 h Combination of fallute to remain o en, leak or ru ture, and lug or fouled Motor Opesated Falls to remain running 1.00E44 h Purn Motor Operated Falls to start 3.50E43 d Purn Operator Recovery Falls to dktgnose and 3.00E42 d Opetator falls to locally/manually recover pump and support systems. Based on a similar recover analysis Action restart SFP Pum from the Tro an IPE for AFW electric m recove Passive Safety Valve Failure 3.75E46 h Inadvertent Actuation SFP Su rt Discharge Level Trip 3.00E46 h Transmltler failure SFP Su rt Flow Tri Failure 3.00E46 h Transmitter failure SFP Support Une from U2 to U1 SFP 1.03E47 h Pipe rupture plus valve failures In the line faflso en SFP Sup ott Loss of Cooling 1.00E45 h Room cooler Inltlall running and falls to remain running.

SFP Sup rt Loss of Power 1.00E45 h LOOP combined with a mean value for loss of load centers from the Susquehanna mini.PRA SFP Supporl Motor Operated Pump 6.00E43 d 3 times the Component Failure Data sate of 2M/d to reflect modeling technique (only one of three pumps h Unavailable due to considered for OOS due to maintenance) test maintenance SFP Support Suction Pressure Ttip 3.00E46 h Event caused by an open or short in the circuit S tern Failure Surge Tank Failure 3.10E45 h Combination of plugged stsalner and tank supture Sur e Tank Level Tri S stem Failure 3.00E46 h Transmitter failure B.12

Common Cause Appendix B Fault Trees This portion of Appendix B documents the identification and analysis of dependent failures to be used in the quantification of the PRA fault trees.

Dependent failures are those failures that defeat the redundancy that is employed to improve the availability of some plant system or function. These common cause failures will be explicitly depicted in the fault tree models.

This PRA does not model all the plant systems, rather it concentrates on the systems required for Spent Fuel Pool Cooling. Information regarding support systems failures will be extracted from the Susquehanna IPE PRA. The adequacy of the modeling of common cause failures in the Susquehanna IPE PRA was not reviewed. Conservatism and/or omissions concerning common cause in the Susquehanna IPE PRA will be reflected in this SFP PRA. The common cause failure probability is calculated from independent failure probabilities and common cause (beta) factors.

Plant-specific data on multiple failures is rare, so data collection for common cause analysis must be done on an industry-wide basis. The EPRI Common Cause Database (as reflected in the Trojan IPE submittal) and NUREG/CR-4550 were chosen as the sources of beta factors for this PRA.

Previous PRA studies provided a guide for selection of the component types for which common cause data would be required. Components modeled in this PRA which were considered for common cause analysis are:

Motor Driven Pumps

~ Check Valves The following table lists these components, failure mechanism, the corresponding beta factor (f) factor, and the source.

Table B.V Component Failure Beta Source Mechanism Factor Check Valve Failure to 2.67E-DI EPRI Corrrrron Cause Database o en Check Valve Failure to 2.67E-01 EPRI Corrrren Cause Database close SFP Motor Failure to 1.30E-01 NUREG/CR-4550, Volume 1, Table Driven Pump start 6.2-1 (Average of RHR and CS pump values)

SVS Motor Failure to 7.41E-02 EPRI Corrrren Cause Database Driven Pum start RHR Motor Failure to 9.86E-02 EPRI Cannon Cause Database Driven Pum start Common cause failure probabilities were calculated using the Multiple Greek Letter (NGL) method. NGL Parameters are estimated by the relationship y - (1+x)/2, where y is the parameter to be determined and x is the preceding parameter. For example, given a beta factor, f, y may be determined as follows:

Common Cause Appendix B Fault Trees

~1+

(B.1) 2 Remaining parameters were calculated in the same manner. Thus for the components of concern:

Table B.VI Failure Y 6 e Base C onent Mechanism Factor Factor Factor Factor Factor Probabilit Check Valve Failure to 2.67E-01 6.34E-01 8. 17E-01 9.08E-01 9.54E-01 1.00E-04 0 en Check Valve Failure to 2.67E-01 6.34E-01 8.17E-01 9.08E-01 9.54E-01 1.00E-03 close SFP Motor Failure to 1.30E-01 5.65E-01 7.83E-01 8.91E-01 9.46E-01 3.50E-03 Driven P start SWS Motor Failure to 7.41E-02 5.37E" 01 7. 69E-01 8.84E-01 9.42E-01 3.50E-03 Driven P start RHR Motor Failure to 9.86E-02 5.49E-01 7.75E-01 8.87E-01 9.44E-01 3.50E-03 Driven P start After the HGL parameters have been determined, the common cause failure probability may be calculated using the following equations. The equation selected is dependent upon the smaller of the number of events found, or the maximum allowable order of common cause events. If failure combinations of two components are developed, the second order failure probability is:

P> p xPiND (B.~)

If combinations of three are developed, the equations used, are:

B. 14

Common Cause Appendix 8 Fault Trees P, = Q.5xP x(1-y) xP/Np (B.3)

Pg = P xy xP+p (B.4)

If combinations of four are developed, the equations used are:

P2 x P x(1 -y) x PJNp (B.5) 3 Pg x P xy x('t 5) xPJNp 1

(B. 6) 3 P4 = p Xf X5 XP(Np (B.7)

If combinations of five're developed, the equations used are:

P2 =

1 xP x(1 y)xP~gp (B.8)

Pg' xP xy x(1 5) xP~Np (B-9)

P4 = xPxyx5x(1 -e)xp+p (B.10)

Ps = P xyx5xexP+p (B. ll)

B.15

Common Cause Appendix B Fault Trees If combinations of six are developed, the equations used are:

P2 = x P x (1 - y) x P+> (B.12) 5 Ps = 1 10 x

p x y x (1 5) x PlNp (B.13)

P4 XpXQ XIX(1 e)XP~No (8.14) 10 P5 = 1 x Pxyxbxex(1.f)xpl~D 5

Po =x Isxyxbxex(xP/ND (B.16)

In the equations above, P is the common cause failure probability, where i is the number of independent failures in the combination, and P is the independent failure probability (taken from the component fat Nre data).

Application of these formulas to the components of concern is documented on the following pages.

B.16

Common Cause Appendix B Fault Trees Table B.VII Common Cause Summary Fa8ure a Components Mechanhm pa pa FaNure lo open 2.8TE45 L28E40 1AOE40 1~45 5.17E47 $ .18E47 1~4$ *tOE47 tATE47 t.15E47 FaSure lo close 2.0 7E4s CNE45 1.0QE44 L28E4$ 1.03E45 t SEOl LlTE40 $ .10E40 W5E4a 0~47 LtOE40 tZIE401.15E40 1 2OE4l Falure lo start a.SSE4a 9.9OE45 2STE4i LSOE45 1ASE45 2A) 1 E4i 9~40 5ATE40 t.TQE4a TASE47 LSQE40 2.19640 185E40 1.7OE48 Fature lo start 2.5QE4S S.OOE45 woE4a aANE45 1AlTE45 1ATE4a LSTE40 L1OE40 9ATE45 '2.75E47 L22E40 tkaE40 1.1OE40 Falure lo start SASE4l 7.7SE4S 1.9OE44 L1SE4$ 1A2E4$ tATE44 7.12E40 4.14E40 MOE44 401E47 447E40 USE40 1ATE40 B.I7

Spent Fuel Pool Arrangement ESW RHR Leak Tight Gales C/l SFPC SFPC B

(3 pumps I I (3 pumps 3 heal I I 3 heat I I exchangers) Cask exchangers) rb CL I Storage Sklmmer I Plt Sklmmer Surge Surge Tank Tank I a Qo

.Span l.P'ue(~ Spe ue

..oo, nit.3 ..

~

Pool (IJnlf;1), C7 SFPC SFPC SS40l 0839 Figure B.l, Spent Fuel Pool Arrangement SV M ra M Cl-ra ra x

V) IXI

Fuel Pool Cooling Simplified Diagram 153018A 153018B 153019A 153019B To RHRS 15301 T 153017 153001 To SFPC Unit 2 153002A 153004A 153045 153013 153009A 153006A Heat Exchanger 1A 15301 0A 153014 153015 Pump 153002B 1B 153004 B 153009 B 153006B 1B 153010B 153018 LU 15300 Qo Heat Exchanger Pump Cl 153009C 153006C 153002C 153004 C 1C 153010C Pump Heat Exchanger 6940 1 0832 Figure B.2, Representative Fuel Pool Cooling (Unit 1 Depicted) -"

Simplified Diagram cu W U

r+ (D H CL lD X Vl

RHR System in Fuel Pool Coolirllode Simplified Diagram 153070A 153070B 153071A 153071B 151070 HV 151 F016A HV 151 F028A 153060 153021 HV 151 F017A 153001 PSV 151 F066A HV 151 F006 HV 151 F010A HV 151 HV 151 F004A 151 F031A HV 151 RHR F047A Service HV 151 151 Water F006A ~

Pump F034A Heat Exchanger 1P202A IE206A HV 151 HV 151 F048A HV 151 FOIOB F006C 151 F031C HV 151 151 F034C PSV 151 F066B F004C Pump 1P202C HV 151 F028B HV 151 HV 161 F004B 151 F031B HV 151 RHR HV 151 F016B I 047B Service HV 151 151 Water F006B Pump F034B Heat Exchanger 1P202B IE206B HV 151 HV 151 FO48B F006D 1st F031D HV 151 F017B HV 151 151 F034D F004D Pump 1P202D 69401083.1 FigUre B.3, Representative RHR Cooling (Unit 1 Depicted) - Simplified Diagram

APPENDIX C EVENT TREES (Initiating Events, Graphical Event Trees)

Appendix C Event Trees This appendix contains the information describing the methods used to generate and select the values used for initiating events, and the graphical representations and discussions for the even't tree (ET). Specifically it contains:

a) Initiating Event Discussion. Contains the information describing the methods used to generate and select the values used for initiating events.

b) Initiating Event Source Table. Table C. I is provided which lists the Initiating Events, values from a variety of sources, the selected value used in this evaluation, and the reason for selecting the value.

c) Initiating Events Frequency Table. Tables are provided which lists the Initiating Events frequency for each Case for both the As-Found and As-Fixed conditions.

d) Top Event Frequency Table. Tables are provided which list the frequency of the top events modeled in each Event Tree. These values are a combination of the HRA and Hardware Top Event Frequencies (See Appendices B and D).

e) NBF Event Trees. The following NBF Event Trees for the As-Found and As-Fixed conditions are provided.

I) Loss of SFPC

2) LOOP

3) Extended LOOP

4) Station Blackout

5) LOCA

6) Flooding

7) Loss of Service Water

8) Pipe Break

9) Seismic

10) LOCA w/LOOP CDF Generic Event Tree. A single generic Event Tree is provided for CDF.

g) Event Sequence Evaluations. Discussions of the important CDF sequences are provided. 0 h) Timelines. Timelines that match the discussions in item g above.

C.I

Initiating Event Discussion Appendix C Event Trees C.l Initiatin Events Initiating events (IEs) are occurrences such as system disturbances or component failures that cause a loss of the SFPC function to one or both SSES units. The analysis initially sought to consider all possible causes of a loss of SFPC and include their contribution in the evaluation and quantification effort.

Initiating events were identified based on:

Review of the concerns raised in the 10 CFR 21 report and associated documentation regarding alleged design deficiencies for an event that causes a loss of SFPC and the plant response to such events.

Review of the SSES IPE and loss of SFPC mini-PRA (SA-TSY-001, Revision 0).

~

The meeting with PP8L on December I, 1993 and SSES plant

'alkdown on December 2, 1993.

~

Review of other IPEs and PRAs of nuclear power plants.

C. l. 1 Description of IEs Selected for Evaluation and guantification The IEs considered, evaluated, and quantified, are described below. The sources of input information used and basis for each estimated IE frequency is provided in Table C-l.

~

SFPC Failure This IE includes all failures in the SFPC system or its components and human errors that would render the SFPC system inoperable. SFPC system piping failures are excluded in order to treat them separately under the pipe break initiating event. The SFPC system failures that could cause loss of SFPC system function are quantified using the zero failure Chi Squared distribution method, The total estimated annual frequency for the SFPC system failure IE is 1.57E-4/YR.

Loss of Offsite Power, LOOP T"..as IE includes all natural and human action occurrences that could cause a loss of power supply to the SSES site from the offsite distribution system whether originated from an onsite or offsite location. The SFPC system is powered from a non-safety power source, not provided with automatic back-up power from the onsite emergency power, supply C.2

Initiating Event Discussion Appendix C Event Trees sources. The SFPC system is therefore de-energized upon a LOOP and remains de-energized until offsite power is restored and the appropriate buses are re-energized or until plant operators align power from one of the plant's five emergency diesel generators. The LOOP initiator event can potentially be followed by a failure of the SSES onsite emergency power back-up power supply, which is treated separately as the station blackout (SBO) IE. Additionally, if the LOOP is not recovered for a period of at least four it is termed and treated separately as an extended

hours, LOOP. The total estimated frequency for the LOOP is 7.00E-2/YR.

~ Extended LOOP, (EX-LOOP) 1 This IE includes all LOOPs as described above which also do not have offsite power restored to SSES within four hours.

The frequency is based on the LOOP frequency times an estimate of the probability of failure to recover offsite power within a four hour period which substantially reduces the resultant frequency. The total estimated frequency for the Extended LOOP is 7.0E-3/YR for > 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , 3.5E-3/YR for

> 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months , and 1.75E-3/YR for > 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months .

Station Blackout, SBO This IE includes all LOOPs as described above which also a failure of all emergency onsite ac power sources 'ncur (four emergency diesel generators) resulting in onl'y station batteries for plant indications and controls. The frequency is based on the LOOP frequency times an estimate of the probability of failure of all four EDGs which substantially reduces the resultant frequency. The total estimated frequency for the SBO is 2.73E-8/YR.

Loss of Coolant Accident, LOCA This IE includes large, intermediate, and small size pipe breaks in the reactor recirculation or other piping system in contact with the reactor coolant. These pipe breaks cause emergency core cooling activation of systems to inject make-up water to the RPV and also cause non-essential electric loads to be shed, including the SFPC system. This results in loss of SFPC until it is successfully restarted.

The frequency is based on the sum of the probabilities of large, intermediate, and small size LOCA pipe breaks. The total estimated frequency for the LOCA is 3.67E-3/YR.

C.3

Initiating Event Discussion Appendix C Event Trees LOCA-LOOP This IE includes the all LOCA as described above which also incur a LOOP. The frequency is based on the LOCA frequency times the LOOP frequency. The total estimated frequency for the LOCA LOOP is 2.57E-4/YR.

Loss of Service Water System, LOSWS.

This IE includes all failures in the SWS or its components and human errors that would render the SWS inoperable. SWS piping failures are excluded in order to treat them separately under the pipe break initiating event. The SWS failures that could cause a loss of SWS function are quantified from referenced PRA/IPE studies to estimated the IE frequency. The total estimated frequency for the loss of SWS failure IE is 2.00E-3/YR.

Internal Flooding, FLOODING This IE includes failures in systems internal to the plant supplying water to the reactor building which could result in accumulation of water in the SFPC room and flood the SFPC equipment (SFP pumps) causing a loss of the SFPC function.

The water system failures that could cause a loss of the SFPC function are quantified from referenced PRA/IPE studies to estimated the IE frequency. The total estimated frequency for the loss of SWS failure IE is 3.90E-3/YR.

~

PIPE BREAK This IE includes failures in the SFPC or SWS piping systems which would cause loss of the SFPC system. The pipe breaks are considered at any location within these systems'hich would result in inadequate flow to the SFPC system or heat exchangers (SWS). Potential flooding induced failures from such potential pipe breaks is treated under the flooding IE above. The total estimated frequency for a SFPC or SWS pipe break IE resulting in loss of SFPC system is 3.43E-3/YR.

SEISMIC This IE includes failures in plant systems that result in loss of the SFPC function as a result o oany seismic event causing ground motion %t the SSES site. The seismic initiator frequency is estimated from NUREG/CR-4550, Volumes 3 and 4 using Revised LLNL median hazard curve probabilities from draft NUREG-1488 (October 1993) at < 0.6g PGA and >

0.6g PGA. The generic fragilities provided in Table 4. 11 of C.4

Initiating Event Discussion Appendix C Event Trees NUREG/CR-4550 are used to identify the weakest link and estimate the associated seismic fragility values for the weakest links in the SFPC system and the RHR in SFPC operating mode. The local accelerations at these "weakest links" are then estimated corresponding to given PGA values.

In this manner the IE frequency at the seismic event magnitudes that would cause loss of SFPC and loss of RHR in the SFPC mode of operation are estimated.

The < 0.6g PGA is estimated to result in accelerations that cause failure of the ceramic insulators for the offsite power supply lines. The ceramic insulators fragility based on generic values form Table 4.11 of NUREG/CR-4550 is at 0.25g. The SFPC system requires offsite power and thus is considered to be rendered inoperable in the seismic event.

All other plant systems and equipment that are not seismically qualified are assumed to fail for seismic events up to 0,6g. Similarly, the seismic event at > 0.6g PGA is estimated to result in accelerations that cause seismically qualified systems and equipment to fail. A seismic event producing a PGA of 0.9g or larger is taken as rendering much of the ECCS equipment inoperable, such that the EOGs, batteries, and RHR in the SFPC mode of operation would not be available. Based on these considerations the estimated IE frequency for a < 0.6g PGA is 8.55E-6/YR., and for a >

0.6g PGA seismic event is 4.20E-7/YR.

C.5

Initiating Event Source Table Appendix C Event Trees Range Point Initiating/Top Source II Source E2 Source P3 Source l4 Susquehanna .Other Estimate (Per Event (T e) (unit) (unit) (Unit (Unit) IPE (Unit) (Unit) Plant Yr) Cannent SFPC Failure ,Fre. Estimated using (Initiating the Chi Squared Event) SFPCF Ref. 2ero failure techni ue.

loss-of- Fre. 0.079/YR 0.078/YR 0.11/YR 0.09/YR 0. 07/15mo. 0.07/YR 0.07/YR LOOP that lasts Offsite-Power (Peach (Zion) (Grand (Oconee) (Susquehanna (Tro]an) for less than 4 that Causes Bottom) Gul f) ) hours duration LOSFPC (i.e., not an (Initiating extended LOOP),

Event) LOOP Ref. HUREG/CR4500 NUREG/CR4500 HUREG/CR455 Oconee IPE Susquehanna Tro]an IPE average of frequency is Vol.4, Vol.7. Rev.l 0 Vol.6, Table 2.1-3 IPE Page F-5 Table values fran taken as the mean Rev.l, Table Table 4.3-1 Rev.i Part 3.1.1-6 sources from the other 4.3-1 I Table studies.

4.3-1 Extended-LOOP Fre. 7.0E-3/YR 94 Extended LOOP that causes hr 3.5E-3/YR frequencies are LOSFPC 910 hr 1.75E- taken as the (Initiating 3/YR 920 hr P(LOOP) times the Event) EX-LOOP probability of non-recovery at times of 4. 10, and 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months , respectively.

The probability of non-recovery Hef. P(LOOP)~P(non- values are recovery 9 estimated using time) the upper bound of the curves in NUREG/CR-4550 developed per NUREG/CR-5032.

P(non-recoveries)

~0.194 hr, 0.05 9 10 hr, and 0.025 9 20 hr.

C.6

Initiating Event Source Table Appendix C Event Trees Range Point Initiating/Top Source /I Source f2 Source f3 Source f4 Susquehanna Other Estimate (Per Event (T e) Unit (Unit) Unit) (Unit) IPE (Unit Unit Plant Yr) Ccmnent Station- Fre. 2.73E-B/YR SBO frequency is Blackout That taken as the LOOP Causes LOSFPC frequency (7.00E-( Initiating 2/YR) times the Event) SBO combined unavail-ability of the Ruf. LOOP frequency four EOIIs times the EOGs (0.025) . This combined is based on an unavailability assumed EOG reli-abilit of 97.5X.

LOCA that Pre. 2.50E-3/YR 3.40E-3/YR 2.50E-3/YR 3.40E-3/YR 5.40E- 5.40E-3/YR 3.67E-3/YR LOCA frequency is Cau"es LOSFPC (Surry) (Peach Bottom) (Sequoyah) (Grand Gulf) 3/15mo. (Oconee) taken as the mean (Initiating (Susquehanna from the other Event) LOCA ) sources and includes small.

Ref. Surry IPE NUREG/CR4550 NUREG/CR455 NUREG/CR4550 Susquehanna Oconee IPE Average of intermediate, and Table 3.3.1- Vol.4, Rev.l 0 Vol.5, Vo).6.Rev.l IPE Page F- Table 2.1- referenced large size LOCAs.

3 8 NUREG/CR Part I Table Rev. I Part Part 1, 112 3 sources 45SO Vol.3, 4.3-1 1. Table Table 4.3-1 Rev.l Part 4.33-1 I, Table 4.3-1

Initiating Event Source Table Appendix C Event Trees Range Point Ini t l atlng/Top Source El Source l2 Source f3 Source I4 Susquehanna Other Estimate (Per Event (T e) Unit) Unit) (Unit) (Unit) IPE (Unit) (Unit) Plant Yr) Conment LOCA with LOOP Fre. 2.57E-4/YR LOCA and LOOP (Initiating frequency is Event) LOCA- "taken as the mean LOOP of the frequency of LOCA times the Ref. Average of frequency of LOOP referenced form the refer-sources enced PRAs and IPEs.

Loss-of- Fre. 9.40E-4/YR I.BOE-4/YR I.OOE-3/YR 5.00E-3/YR 4.30E-3/YR 2.00E-3/YR Loss of Service Servlce-Mater (Lion) (Olablo (Tro]an) (Oconee) Mater Systee fre-That Causes Canyon) quency is taken SFPC ( Initiat- as the mean of ing Event) Ref. Olablo Canyon the frequency of LOS'W HUREG/CR45 Tro]an IPE HUREG-3662 Oconee IPE average of 50 Vol.l. IPE Table Table 2.1- referenced loss of SMS fore Rev.i, Table 3.1.1-6 3 sources the referenced 4.3-1 PRAs and IPEs.

Flooding That Fre. 1. OOE- 3.90E-3/YR 3.90E-3/YR Causes Flooding LOSFPC 4/15mo. (Oconee) frequency ls (Initiating (Susquehanna taken from the Event) ) Oconee IPE for FLOODIHG Ref.

Internally Susquehanna Oconee IPE From Oconee initiated floods IPE Page F- Section IPE from a large 341 Section 3.3.2.3 auxiliary F.4.4.1.1 Page 3.3- building flood.

12 SMS Pipe-break Fre. 4.70E-5/YR 9.90E-3/YR 2.00E-4/YR 3.40E-3 that Causes 5'MS pipe rupture ls taken as the LOSFPC mean of the SWS (Inl tl at lng Pipe rupture fre-Event) SVS .Ref. Vo et al. HUREG/CR4550 WAS!I-1400 ,average of quencies form the PIPE-BREAK 1990 Vol.2 referenced referenced sources sources.

C.8

Initiating Event Source Table Appendix C Event Trees Range Point Initiating/1'op Source Il Source I2 Source I3 Source l4 Susquehanna Other Estimate (Per Event (T e (Unit) (Unit) (Unit) (Unit) IPE Unit (Unit) Plant Yr) Coament Seismic That 8.5SE-&/YR 0 < Seismic initiator Causes LOSFPC 0.6g PGA frequency Is (Initiating 4.20E-7/YR 0 > estimated using Event) SEISHIC 0.6g PGA the Revised LLNL median hazard tables pf prob-abilities at <

0.6g PGA and >

0.6g PGA. The 0.6g PGA is taken as causing spec-tral acceler-ations at thrice NUREG.CR4550 the general HCLPF Vol.4. Rev.l, value. This is Part 3. Table believed to be a 4.9 and draft reasonable NUREG-1488 estimate of the (October 1993) maximum size page A-15. seismic event that the ECCS equipment could survive and remain C.9-

Initiating Event Frequency Tables Appendix C Event Trees The values from Table C. I were ratioed with the time spent in each Case to provide an Initiating Event Frequency for each Case.

Table C.II SSES As-Found Initiating Event Frequency Case Initiating Event Frey Loss of SFPC 1.57E-04 1.35E-04 7.19E-06 8.63E-06 2.88E-06 2.88E-06 LOOP 7.00E-OZ 6.04E-OZ 3.21E-03 3.85E-03 1.28E-03 1.28E-03 Extended LOOP 7.00E-03 6.04E-03 3.21E-04 3.85E-04 1.28E-04 1.28E-04 SBO 2.73E-OB 2.36E-OB 1.25E-09 1.50E-09 5. 01E-10 5. 01E-10 LOCA 3.67E-03 3.17E-03 1.68E-04 2.02E-04 6.72E-OS 6.72E-05 Floodin 3.90E-03 3.36E-03 1. 79E-04 2. 14E-04 7.14E-05 7.14E-OS Loss of SMS 2.00E-03 1.73E-03 9. 16E-05 1. 10E-04 3.66E-05 3.66E-OS Pine Break 3.40E-03 2.93E-03 1.56E-04 1.87E-04 6.23E-OS 6.23E-OS eismic <.6 8.55E-06 7.37E-06 3.91E-07 4.70E-07 1.57E-07 1.57E<<07 eismic ~).6 4.20E-07 3.62E-07 1.92E"08 2.31E-OB 7.69E-09 7.69E-09 OCA w/LOOP 2.57E-04 2.22E-04 1.18E-05 1.41E-OS 4.71E-06 4.71E-06 Table C.III SSES As-Fixed Initiating Event Frequency Case Initiating Event Freq 4 Loss of SFPC 1.57E-04 1.35E-04 7. 19E-06 8.63E-06 5.75E-OB LOOP 7.00E-02 6.04E-02 3.21E-03 3.85E-03 2.56E-03 Extended LOOP" 7.0QE-03 6.04E-03 3.21E-04 3.85E-04 2.56E-04 580 2.73E-OB 2.36E-OB 1.25E-09 1.50E-09 1.00E-09 LOCA 3.67E-03 3. 17E-03 1. 68E-04 2.02E-04 1.34E-04 Floodin 3.90E-03 3.36E-03 1.79E-04 2.14E-04 1.43E-04 Loss of SMS Z.OOE-03 1. 73E-03 9. 16E-05 1. 10E-04 7.33E-OS Pine Break 3.40E-03 2.93E-03 1.56E-04 1.87E-04 1.25E-04 Seismic <<.6 8.55E-06 7.37E-06 3.91E-07 4.70E-07 3.13E-07 Seismic ~>.6 4.20E-07 3.62E-07 1.92E-OB 2.31E-OB 1.54E-OB LOCA w/LOOP 2.57E-04 2.22E-04 1.18E-OS 1. 41E-05 9. 41E-06 C.10

Initiating Event Frequency Tables Appendix C Event Trees Table CeIV SSES As-Found Top Event Frequency Ihrtlaohg lactated lactated Isolated lactated Crossm Isotated Corno TSC Kent Ut US Ut RHR UZ RHR Ut Ut or U2 Ctrected SFPC SFPC System System Repair . Re carr A!ramate Restart Restart Rec Rec Cooang Rec. Rec Loss ot 1.000 N/A 0.029 N/A 0.020 0.103 0.050 N/A 0.050 N/A N/A SFPC 1.000 N/A 0.004 0.326 N/A 0.023 0.103 0.050 N/A 0.050 N/A N/A N/A N/A N/A N/A N/A N/A N/A 0.100 N/A N/A 1.000 N/A 0.006 0.059 N/A 0.050 0.108 0.100 N/A 0.100 N/A N/A 1.000 N/A 0.010 0.109 N/A 0.100 0.118 0.500 N/A 0.100 N/A N/A L P 0.010 0.010 0.010 0.059 0.059 0.050 0.108 0.100 0.100 0.100 N/A N/A 0.010 0.010 0.010 0.307 0.059 0.053 0.108 0.100 0.100 0.100 N/A N/A N/A N A 0.020 NA NA 0.109 N/A N A N A 0.200 N/A N/A 0.020 0.010 0.020 0.109 0.059 0.100 0.118 0.200 0.100 0.200 N/A N/A 0.050 0.020 0.020 0.029 0.059 0.100 0.148 0.500 0.100 0.200 N/A N/A 0.020 0.020 0.020 0.109 0.109 0.100 0.11S 0.200 0~ 0.200 N/A 0.100 LOOP 0.020 N/A 0.020 N/A 0.020 0.426 N/A 0.109 0.103 0.118 0.200 0.200 0~ N/A 0.100 0.050 N/A N/A N A N/A 0.350 N/A 0.200 0.050 0.020 0.050 0.209 0.109 0200 0.148 0.350 0.200 0.350 N/A 0.200 0.100 0.050 0.020 0.050 0.050 0.309 0.109 0.200 0.198 0.500 0~ 0.350 N/A 0.300 0.050 0.209 0.209 0.200 0.148 0.300 0.300 0.300 0.200 N/A 0.050 0.050 0.050 0.526 0.209 0.203 0.148 0.300 0.300 0.500 0.200 N/A N/A N/A 0.100 N/A N/A N/A N A N A 0.500 N/A 0.100 0.050 0.100 0.359 0~ 0.350 0.198 0.500 0.300 0.500 0.350 N/A 0.200 0.050 0.100 0.509 0~ 0.350 0.298 0.800 0.300 0.500 0.500 N/A 0.050 N A 0.050 N/A N/A 0.109 0.118 0.100 N/A 0.100 N/A N/A 0.050 N/A 0.050 N/A N A 0.109 0.118 0.100 N/A 0.100 N/A N/A N/A N/A 0.100 N/A N/A N/A . N/A N A 0.200 N/A N/A 0.100 N/A 0.100 NA N/ 0.209 0.148 0~ N/A 0400 N/A N/A 0.200 N A 0.100 N/A N/A 0.209 0.198 0.500 N/A 0.200 N/A N/A ood 0.010 N/A 0.010 0.059 N/A 0.050 0.108 0.100 N A 0.100 N/A N/A 0.010 N A 0.010 0.376 N/A 0.053 0.108 0.100 N A 0.100 N/A N/A N/A N/A 0.020 N/A N/A 0.109 N/A N/A N/A 0~ N/A N/A 0.020 N A 0.020 0.109 N/A 0.100 0.118 0~ N/A 0~ N/A N/A Loss cf 0.050 N/A 0~ NA 0.100'.050 0.148 0.500 N/A 0.200 N/A N/A 0.010 N/A 0.010 0.059 N A 0.10S 0.100 N/A 0.100 N/A N/A SWS 0.010 N/A 0.010 OM6 N/A 0.053 0.108 0.100 N A 0.100 N/A N/A N/A A 0.020 N/A N/A 0.109 N/A N/A N A 0.200 NA N/A 0.020 N/A 0.020 0.109 N/A 0.100 0.118 0~ N/A 0.200 N/A N/A 0.050 N/A 0.020 0~ N/A 0.100 0.148 0.500 N/A 0200 N/A N/A ipe 0.010 ~

N/ 0.010 0.059 N/ 0.108 0.100 N/A 0.100 N/A N/A Break 0.010 N/A 0.010 0.376 N/A 0.053 0.108 0.100 N/A 0.100 N/A N/A N/A N/A 0.020 N/A N/A 0.109 N/A N/A N/A 0.200 N/A N/A 0.020 N 0.020 0.109 N 0.100 0.118 0.200 N/A 0.200 N/A N/A 0.050 N/A 0.209 NIA 0.100 0.148 0.500 N/A 0.200 N/A N/A etsmtc NA NA 0.109 0.109 N A N/A 0~ 0~

N A N/A N/A N/A N/A 0.426 0.109 N/A NA 0~ 0~ 0200 0~

N A N/A N/A N/A N/A N/A 0209 N/A N/A N/A 0.350 N/A N/A N/A N/A 0~ 0.109 N/A N A 0.350 0.200 0.350 N/A N/A N/A N/ 0~ 0.109 N/A N/A 0.500 0~ 0.350 N/A 0.100 0.050 0.100 N/A 0.109 0.209 0.198 0~ 0.200 0~ N/A 0.100 w/

LOO P 0.100 0.050 0.100 N/A 0.109 0.209 0.198 0.200 0~ 0.200 N/A 0.100 N/A N/A 0.100 N/A N A NA A N/A 0.350 N/A 0.100 0.100 0.050 0.100 N/A 0.109 0.198 0.350 0~ 0.350 N/A 0.100 0.100 0.050 0.100 N 0.109 0.198 0.500 0~ 0.350 N A 0.100

Initiating Event Frequency Tables Appendix C Event Trees Table C.V SSES As-Fixed Top Event Frequency lnitiaang Event mbrned mbined mained D 's 5th 0 SFPG RHR System U1 or U2 Directed Recavery Recovery Restart Repair Alternate Recovery Recovery Cooling Loss ot SFPC 0.010 0.050 N/A N/A 0.013 0.050 N/A N/A 0.029 0.100 N/A N/A 0.020 0.100 N/A N/A LOOP 0.006 0.020 0.100 N/A N/A 0.100 N/A N/A 0.010 0.059 0200 N/A

'/A 0.010 0.050 N/A N/A Extended Loop 0.010 N/A 0.100 0.010 0.053 0200 N/A 0.100 0.020 0.109 0.350 N/A 0.020 0.100 0.350 N/A 0200 BO 0.020 0.100 0.300 N/A 0.020 0.103 N/A 0.350 N/A 0.050 0.500 N/A LOCA 0.050 0.109 0.100 N/A N/A 0.103 0.100 N/A N/A 0.100 0200 N/A N/A 0.100 N/A N/A Flood 0.010 0.050 0.100 N/A N/A 0.010 0.053 0.100 N/A N/A 0.020 0.109 N/A N/A 0.020 O.10O N/A N/A Loss at SWS 0.100 N/A N/A 0.006 0.023 0.100 1.000 N/A N/A 0.010 0.059 N/A N/A 0.010 0.050 N/A N/A Pipe Breatt 0.010 0.100 N/A N/A 0.010 0.'100 N/A N/A 0.020 0.109 0200 N/A N/A 0.020 0.100 0200 N/A Seismic N/A 0.100 0200 N/A N/A N/A 0.103 0200 N/A N/A N/A N/A N/A N/A 0.200 N/A N/A LO w/LOOP 0.100 N/A 0.100 0.100 0.203 N/A 0.100 N/A 0.100 0.350 N/A

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~ 85EOS 4 89EOS 4 0(E45

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OOennctac C Event Trees SSO ICrass>>ed) ca Sa)n das Trer)ere r If EOO Re>> Comb SFPC Comb RHR Reoor Rec M Coasnd

~ oof41 0 dof 41 ~ OTE41 7 OOE41 0 OOEcOO 1ROE49 2.0OE41 2.IS)E42 10SE4) SS)OE41 100fcOO 1 ddf49 S54E 11 2 Sdf.t I SOOE 11 204E 12 2445 12 s ~ IE 12 0 OOEsod 11SE.12 1 2SE 12 12SE 12 2 sOE49 s 99E.10 S OOE. 10 Taco) 1 OOE44 5 obf.ld 0 OOEsoo 2 s9E cesl 2 ETs 1.99E49 5 OOE.I ocsl NSF 50of \

LOCA (Crass>>ed)

Rec)err Rec M Coasnd ca Sad) Sas Trans)sr IE Cone SFPC Comb RHR 9 SOE41 0 OTE41 9 OOE41 0 OOEH)O S.OOE42 1 OSE41 15)OE41 1.00fcoo S.Ides 1 41E45 1,7SE45 I.TSE4T I,TSE47 Taco) 1 TSE47 5 >>2E acsI 2 ETs 2 ssf 4c 1 75E4 ocel Nsf 1.75 f4 f)sacer)4 (Crassaed)

Carre Sf PC Con>> RHll Reoen Rec M Ceased 9 99541 9 OOE41 9 S1E41 9 OOE41 0 Oof coo 1.12E4c I OOE41 5 SOE42 1.00E41 1 Oof coo 1 05E4s 1 12E4s 5 TsE44 d TSE44 1 ITE44 S SOE41 5 74547 0 Oof roo 0 OOE+OO S 74544 S 74544 S 74544 712f4C S 74E44 OOOEK)0 7.12E ace) 1 ETs 7 12E4I s 14E eccl NSF Lass al SWS ICrass.eed)

IE Cane ffPC Comb RHR Reoennec MCacwnd 1 004 sOO OOCE41 9TTE41 OOOE41 000fsOO 5 d5E4S 4 Oof 45 2 SOE42 'I.OOE41 I Oof coo 2 1sE45 21SE44 1 IOE44 S SSE44 s 5IE40 505544 0OOE coo 5 OSE49 5 OSE49 5 s2E ale) 2 ETs S 45E41 5 05E csel NSF

hpponda C ant Iroos IE 9 OQE4) 9OOE41 947E41 9OOE41 000&00 1.00E42 BSOE42 1.00E41 1.00&00

)4544 8 14E44 0

5 80240 5 BQE40 2 OSE4T 2 90E47 2 29E47 2 29848 2 2QE40 0 BOER Oto)2 ETS 0 20E44 2.29E ots) HBF

)E cons) RHR Roose Rec Ak Cooin0 ok Botn Boo Tmnste<

0 OTE41 0.00E41 0 BOERS I.OSE41 2.00E41 1.00&00 0 OOE47 0 OOE47 T.QOE47 0 4SE40 0 4SE40 0 OIE40 0 00&00 1 81E48 I 01E40 1 BIE40 7.04E47 I 01E40 OOOEi00

'I OSE 22 atH 2 ETs 7.04E47 I 01E otal HBF I 01E LOCA ts)UTCtt ICn)eooea) EndHste E. Pew Rec Se EDQ CamoSFPC Coma RHR ReosrRec ABCoosno I BOERS 9 OOE41 9 OOE4t 9 OOE41 'T.OTE41 0 OOE41 0 DOE+00 204E45 105842 I OOE41 1.00841 2.0584) 2.00E41 I.OOEe00 2 OQE45 2 STE45 I QSE40 2 22E40 2 77847 5 77E47 4 71847 0 OOE+00 000f 400 9 42E40 9 42E40 9 el 840 2 54E45 t OQE47 I OOE47 222E47 I TTE48 222E40 0 008 ~00 0 OOE~OO 900E 10 9OOE 10 9 OOE.IO 2 40E47 I OSE40 2 40E48 0 008+00 0 OOEe00 99QE 10 OQQE 10 999E 10 2 SSE45 9 01E40 2 54E oW2 Ets 2.25845 OBIE otVNBF 9 01E

Appendcc C Event Trees LOSS or SFPC ICtbsebed)

CorrbSFPC COmb RIIR ReObr RIC A&CO<<no 1 Ooftbo 0 CO&00 0 71E41 9 Oof 41 0 Oofcoo L72 f45 1 t27faM 2.NE42 1.OOE41 1.00Eaoo 1.72E45 1 OTE45 1 07545 1.72E45 S SIE47 ~ 5I f41 5 OIE47 5 OIE48 S OIE40 1 71E4S 5 OIE4& OOOEsoo 1 72E stall ETs 1 TIE45 50IE otal NBF 5 OIE LOOP ICroasbsdl 0 92E41 E Pew Roc Comb SF PC 1 OOE41 9&OE41

'I OIE4l Comb RHR OSIE41 SNE42 Roost Rec OOOE41 20CE41 0~

A& Co<<tto Looftoo ok B<<n Bos T rentier 0 NE45 0 OSE45 0 TTE45 0.77 f45

&27E40 8 SIE47 0 SIE47 7 OOE4I Tcaal &.SIE47 T.dOE4I 4075 I cast 2 ETI 0 00E45 8 5IE4 ot<< IIBF d SIE47 Etsendsd LOOP (Croaoaedl IE L Pow Rso Stn EDG Comb SFPC Comb RHR Reoor Rec A&Cootno 0 09541 50OE4'I 0 COE41 9 00041 8 01E41 0 50E41 0 oof kXI 7 0554l SOOE41 2OOE41 2OIE42 1.09E41 S SOE41 '1 COERCE S 7554I S NE4l 0 91E40 0 07E40 7 NE40 5 57E41 5 51541 d 50541 0 Oofsoo 0 00&00 S OOE47 S OOE41 S OOE41 1 OOE4I S OTE4I 5 5&E40 l ISE41 4 ssf 47 0 &SE47 0 COEaoo 2 IOE41 2 lbf41 S NE4I 0 &SE45 7 00545 s eSE40 S SSEM 9 5&540 2 95540 2 9SE40 2.NE45 Tot<< 1 OSE4I S lTE45 0oof ebb 7,0OE 2.17E.1 stat 2 ETa 7 &sf4I 5 sTE tasl HBF s eTE

Bpbentlct C Evortl Trees IE EDG Rec Comb SFPC Comb RHR Rear Rec As Coeeto 5 SOEOl 0 50E41 7 91541 5 OOE41 0 OOEe00 1 99E40 2 SOE41 5 OI f42 2.00E41 5 COE41 I.OOE400 1 SSE40 7.75E 11 7.75E.11 0 01E.11 I.OSE 11 1 OSE 11 2.05E 11 1 taf. ~ 1

\ Osf.t I 10SE 11 2 99540 1 OSEOS Tote \ 04549 1 OSE49 0 OOE~

414E2 eal1ETl 104549 105E otal NSF 1 05t'E LocA Ioeeesereto Comb SF PC Comb RHR Reoer Rec Ak Cootns Ben Boe Tranerer 0 OOE41 8 OOE41 8 OOE41 0 OOE r00 4.02E44 1.00 f41 2.00f41 2.00E41 T.OOfr00 2 51EOI S 51EOI 4 02EOI 5 25E45 1 81EOS 1.51EOS I 51545 1 51E45 0 OOEe00 4 02EOl

~5 42E.

otal 2 ETe 4 OOE44 1 51E otal NBF 1 51E Floodtlo (Croll aed) fnceee IE Cere SFPC Corno RHR Reoer Rec Alt Coeno ok Both Bel T rentier Comment 9 99E41 9 SOEOI 8 91EOI 8 OOEOl 0OOEr00 8 54E44 10IE42 I.OOEOI 1.00E41 10OEe00 8 2 7EOI 8 STEOI I 5SERS ~ SSEOS I 74545 1 SSEOS 1 9 I f45 0 OOE~CO 0 OOE F00 5 82E47 5 82E47 2 82E47 8 5IE44 2 82EOT 0OOENO 0 Sef

~ 108E I otal'Tl 0 SIEOI 2 8254 otal NBF LOll Ol SWS ICrON eccl IE CornbSFPC CenbRHR ReoerRec Aacoeno I OOE rOO 9 00E41 0 41E41 8 OOEOI 0 005 +co 4 SIEOI 1 04E42 5 0SE42 1 OOER1 I OOOO 4 SSEOl 4 SSEOI

~ STEM 2 1TE4'I 2 I TE47 2 71547 0 005~00 5 42E48 5 42548 S 42E48 4 58544 S 42EOS 5 42E oul2ETe 458ERI 542E oteNBF 5 42E

~mmmmmmm~uamn~~~~~~~~

~mnmmzmrunmmzaz~~~~~~~

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Appent)N C Eeent Trees IE EQG Rsc Comb SFPC Carne RHR Reoer ReC AS CecanO I SOE41 I SOE41 I OOE41 S.OOE41 0 OOEr00 S.OOEOZ ZASEO) 500E41 1.00Er00 1 2SEa 5.10E 11 5 10E.N 040E 11 0 40&12 I 40E.12 1 SOE 11 0.40&'l2 0 40&12 040E 12 SOOE 10 0905 10 LEOS 7 CSE 10 OOOENO ZOOE 4 14E-otal 2 ETs 1.20E40 7 05E.1 otal H sr 7 05&1 LOCA (cmsoeoc)

Comb SF PC Corrb RHR Reowr Roc A)t Cotano 1 00&00 I OOEO) I OOEO1 I OOEO'1 0 OSE+00 Z.OIEOI 1.00E41 2.00EO1 Z.OOEO) 1.00&r00 2 41EOt 1 41EO4 ZSSE44 1.14E4$ 2.14E45 2 SSE4$

5 ssEa 1.07E45 1 OTE40 Total Z.STE44 1 07EOS 0OOEsOO 2 SIE otal 2 ETs 2,07544 1 OTE otal NSF 1 OTE F (Croseeoo)

IE Comb SFPC Comb RHR Rober Rec A)t CoosnO 9 OOE41 9 IOE41 9 OOE41 I OOE41 0 00&00 S SOE44 1 OOE42 1 COE41 Z.COE41 1 OOEs00 5 SIE44 5 SIE44 5 SOE44 1 OSEOS 1 OSE4$

1 llE45 I 12E47 9 12EOT 1 14E45 OCEANO OOOEi00 2 2IEOT 2 25547 Z.ZIE47 2ZIEOT 5 OOE otal 2 ETs 5 OOE44 2 1IE4 atal lldF 1 2IE Loss or Sws (cross.esc)

)E Comb SF PC Comb RHR Ros<<r Rsc AS Coolno 1 OOE+00 9 00541 I SOE41 I OOE41 0 2 OZE44 ~ OOE42 $ 01EOZ Z.OOE41 1 COEN)0 2 IIEOt 2 02EO4 2 TIEa 2.7IE40 1.1TE47 1.17E47 1 4SE47 0 OOEi00 2 OSE4S 1 OSEOI 2 osEa 2 02E4i 2OSEOI OOOO Z.OZE otal 2 ETs 2 02E44 Z.OSE rarsHOF 2 OSE

AOOdnrTa C Event Treea Comb SFPC COmb RHR Reear Reo AO Ceebnd oe, Doer Dol Tmneler Cornrnanl 9 80641 D OOE41 8 OOE41 0 00fe00 2,00E42 1.00641 2.00E41 1 006r00 e 006 4e e 80648 0 OIE40 ~ oaf 40 7 95647 7.95647 9 98647 I.OOE47 1 99647 e QSE41 'I 99647 0 006~00 e OSE41 Olal2ETe 890E41 ~ OQE4 ocNNDF I OQE47 comb RHR Reoor Rec Alt CocenD 1 OOEe00 8 OOE41 8 50641 0.006 rOO 0.24647 2.00641 S.50641 1.006r00 e,QQE47 e QQE47 028647 8.11E40 0.'IIE40 12$ E47 8 27f48 8 STE48 e STE48 5 DOE47 e 57648 028 f'rN2 ETa 5 00647 e STE mat NSF e STE LOCA rrrUXIP (Croeaeae) Enoaoee IE E PowRec QnECG Corno sFPC comb RHR Reoor Roc AO coceno oe Dain Bol 1ranaral Oonrnerg I OOE+00 9 9OE41 d OOE41 0 OOF41 0 50641 4 50641 0 tOEeOO I 88E4$ 1 05E42 2.00641 2.00E41 $ .50E41 S 50641 I.DOE rOO 1 48645 1 edE45 1 OSE45 2 4 IE40 2 ~ 1E45 2 7 IE40 0 elE47 0 eiE47 0 00&00 0 OOE+00 e SsE47 e 55E47 ~ $ 5E47 I 8864$

1.28E47 I 28E47 1 58E47 2 OSE48 2 05E45 7 ITE49 7 ITE49 I 10640 0 DOE r00 0 DOE+00 S 80649 1 97647 I SSE48 0 Obf iob e 05648 8 dsf49

\ dsf 45 8 bsE47 0 DOER 1 086 S SOE.21 real 2 ETa I 85645 e DSE4 rear NSF

CDF Generic Event Tree Appendix C Event Trees Generic Core Dame Frequency (CDF) Event Tree EQT Near Boi6ng lactation/ ECCS Faiture Frequency Recovery

-CS

-SOTS - LPSS

- HVAC - HPStS Wire Water - Phf - Foihvv EOP

-Etc. - CRDP Wc.

Wc. Sequence End-State From NBF 1.0 - 081 1.0 - 0.1 0.1 - 0.001 creen Vatue 0.1 0 0.01 c~nCA) Key:::kr'.

Figure C.l, CDF Generic Event Tree C.64

Event Sequence Evaluations Appendix C Event Trees Event Sequence Evaluation: Events Occurring in Case 3 As-Found Plant Conditions (see Figure C.2 for timeline representation of this sequence).

INITIAL PLANT CONDITIONS The plant's initial conditions are: ,Unit I is being refueled with the core offloaded into the SFP, Unit 2 is at normal operating conditions, the Unit I and Unit 2 SFPs are cross-connected, the Unit I SFPC system is out of service due to a Service Water System outage and SFPC is provided from Unit 2 with three SFPC pumps running, Unit I has no RHR available for operation in the SFPC assist mode because of maintenance, and Unit 2 has one train of RHR available for operation in the SFPC assist mode.

FROM INITIATING EVENT TO NEAR BOILING CONDITION IN THE SFPs The initiating event occurs at time zero. LOOP, EXTENDED LOOP, and LOCA with LOOP cause a complete loss of offsite power to both units. LOCA'and LOCA with LOOP involve a large, medium or small break LOCA in the operating unit and result in loss of SFPC and'cause RHR of the LOCA unit to be unavailable for SFPC assist. Coincident with all these initiators, Unit 2 scrams and the SGTS and the recirculation system automatically starts. Plant operators respond to the event in accordance with emergency procedures and the TSC is activated within one hour after the initiator. Note that for As-found plant conditions, the LOOP emergency procedures did not prompt operators to ensure SFPC is returned to service. Operators at both units continue with emergency actions for these events. Offsite power is restored within four hours for the LOOP event and after restoration of offsite power, operators return systems to their normal alignments. Operators of Unit 2 may attempt to perform a rapid restart of the plant within the first 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after the LOOP. The TSC would deactivate by 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after the LOOP based on recovery of offsite power and operator's successful handling of emergency plant actions for the LOOP. For the EXTENDED LOOP and LOCA or LOCA with LOOP events, the TSC would not be deactivated throughout the event as mitigation activities continue. For all these event sequences, the SFPs would reach the technical specification limit of 125'F at approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the initiator assuming that operators at both units do not restore SFPC to service. Operators are trained to comply with technical specifications, therefore at or near 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the initiator the operators would recognize the need to restore cooling to the SFPs. At 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the initiator, the operators would attempt to use the available systems to return cooling to the SFPs. This would involve restart the Unit 2 SFPC system, return the Unit I SFPC system to service, or align a train of RHR from Unit I or Unit 2 for operation in the SFPC assist mode to

.restore cooling to" the SFPs, as system availability allows. These actions would continue persistently as the SFPs continued to heat up and approach near boiling conditions. Within 10 to 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months after the initiator, the operators may attempt to provide SFP cooling by alternate means such as ESW, Fire Water, Pumper Truck, or other feed and bleed cooling alignments.

C.65

Event Sequence Evaluations Appendix C Event Trees FROM NEAR BOILING CONDITIONS IN THE SFPs TO CORE UNCOVERY Without restoration of cooling to the SFPs within 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months after the initiator, the SFPs would reach near boiling conditions causing an increased rate of steam release from the surface of the SFP. Under SFP boiling conditions, the rate of steam release to Zone 3 will exceed the capacity of the normal HVAC system and the SGTS for removal of this energy.

recirculation system is left running the steam spreads to the reactor If the building. Approximately eight hours after the SFPs reach near boiling conditions (33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the initiator), the steam spread to the reactor building is assumed to cause ECCS equipment failure due to adverse temperature conditions. If the TSC was deactivated (LOOP event) it would be reactivated at about 33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the LOOP based on ECCS equipment failures. If Unit 2 was restarted earlier, it scrams or operators perform a controlled shutdown due to ECCS equipment failures. The operators and TSC would make every effort possible to provide core cooling using any available means including:

any surviving Unit 2 ECCS equipment,'

ECCS equipment from Unit I that could be crosstied to Unit 2 given that the Unit I reactor building was isolated from Zone 3 for refueling conditions, or equipment outside the reactor building of Unit I or Unit 2 such as feedwater, condensate, standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service water, or pumper truck.

Host of these alternate cooling mechanisms are identified in the emergency procedures. The reactor core would begin to uncover at approximately 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months after the initiator if all these actions related to restoration of cooling to the SFPs with alternate cooling methods, isolation of Zone 3, and restoration of core cooling to Unit 2 were to fail.

ORDER OF MAGNITUDE ESTIMATION OF CONDITIONAL CORE DAMAGE FRE(UENCY GIVEN THE INITIATOR IN CASE 3 CONDITIONS The event tree presented in Figure C.2 presents the sequence flow path that could lead to core damage given near boiling conditions from the Case 3 initiating event. The general functional failures that would have to occur before the sequence could reach a core damage end state and order of magnitude estimations of their associated failure likelihoods are as follows:

~ Failure'f alternate methods for cooling the SFPs that were not credited o in the estimation of the NBF as well as failure of operators to isolate Zone 3 from the Unit 2 reactor building within approximately 33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the initiator. The failure occurs if operators do not implement alternate feed and bleed cooling to the SFPs using one of at least three possible systems and also do not isolate the Zone 3 air space from -Zone C.66

Event Sequence Evaluations Appendix C Event Trees 2 air space. The likelihood that these actions would fail given approximately 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months between exceeding the SFP temperature technical specification limit and failure of ECCS equipment in Unit 2 is estimated at 0.1.

Failure of and non-recovery of all Unit 2 ECCS equipment that would normally be capable of providing sufficient long term decay heat removal given the initial short term post scram functions are completed prior to failure of the ECCS equipment. The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, and other activities is estimated at 1.0.

~

Failure of all equipment outside the Unit 2 reactor building including ECCS equipment from Unit I that could be crosstied to Unit 2 or equipment outside the reactor building of Unit I or Unit 2 such as feedwater, condensate, standby liquid control, reactor water cleanup,.

fire water, control rod drive maximized, RHR service water, or pumper truck. Host of these alternate cooling, mechanisms are identified in the emergency procedures. The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, and other activities is estimated at 0.01.

The overall order of magnitude estimate of the conditional core damage frequency due to an initiating event in Case 3 is the product of the estimated NBF and the three general functional failure estimation above. This product is summarized in Table C.VI below.

Event Sequence Evaluation: Events Occurring in Case 4 As-Found Plant Conditions (see 'Figure C.3 for timeline representation of this sequence).

INITIAL PLANT CONDITIONS The plant's initial conditions are: Unit I is being refueled with the core offloaded into the SFP, Unit 2 is at normal operating conditions, the Unit I and Unit 2 SFPs are not cross-connected, the Unit I SFPC system and Unit 2 SFPC system are both inservice, each with three SFPC pumps running, Unit I has two trains of RHR available for operation in the SFPC assist mode, and Unit 2 has one train of RHR available for operation in the SFPC assist mode.

FROM INITIATING EVENT TO NEAR BOILING CONDITION IN THE SFPs The initiating event occurs at time zero. LOOP and EXTENDED LOOP cause a complete loss of offsite power to both units. The LOCA event involves a large, medium or small break LOCA in ghe operating unit and result in loss of SFPC in the operating unft and causes RHR of the LOCA unit to be unavailable for SFPC assist. Coincident with all these initiators, Unit 2 scrams and the SGTS and the recirculation system. automatically starts. Plant operators respond to the event in accordance with emergency procedures and the TSC is activated within one hour after the initiator. Note that for As-Found plant C;67

Event Sequence Evaluations Appendix C Event Trees conditions, the LOOP emergency procedures did not prompt operators to ensure SFPC is returned to service. Operators at both units continue with emergency actions for these events. Offsite power is restored within four hours for the LOOP event and after restoration of offsite power, operators return systems to their normal alignments. Operators of Unit 2 may attempt to perform a rapid restart of the plant within the first 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after the LOOP. The TSC would deactivate by 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after the LOOP based on recovery of offsite power and operator's successful handling of emergency plant actions for the LOOP. For the EXTENDED LOOP and LOCA events, the TSC would not be deactivated throughout the event as mitigation activities continue. For all these event sequences, the SFPs would reach the technical specification limit of 125'F at approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the initiator assuming that operators at both units do not restore SFPC to service. Operators are trained to comply with technical specifications, therefore at or near 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the initiator the operators would recognize the need to restore cooling to the SFPs. At 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the initiator, the operators would attempt to use the available systems to return cooling to the SFPs. This would involve use of any surplus capacity available from the EDGs ta power non-safety buses under LOOP or EXTENDED LOOP conditions, to support operation of the SFPC system. Offsite power may be recovered within 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months after the LOOP. If the power becomes available to the non-safety bus for SFPC, operators would attempt to restart any available SFPC system to service, cross-connect the Unit I and Unit 2 SFPs if possible, or align a train of RHR from Unit I or Unit 2 for operation in, the SFPC assist mode to restore cooling to the SFPs, as system availability allows. These actions would continue persistently because the SFPs continued to heat up and approach near boiling conditions. Within 10 to 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months after the initiator, the operators may attempt to provide SFP cooling by alternate means such as ESW, Fire Water, Pumper Truck, or other feed and bleed cooling alignments.

FROM NEAR BOILING CONDITIONS IN THE SFPs TO CORE UNCOVERY Without restoration of cooling to the SFPs within 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months after the LOOP, the SFPs would reach near boiling conditions causing an increased rate of steam release from the surface of the SFP. Under SFP boiling conditions, the rate of steam release to Zone 3 will exceed the capacity of the normal HVAC system and the SGTS for removal of this energy. If the recirculation system is left running the steam spreads to the reactor building. Approximately eight hours after the SFPs reach near boiling conditions (33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the initiator),

the steam spread to the reactor building is assumed to cause ECCS equipment failure due to adverse temperatures conditions. If the TSC was deactivated (LOOP event) it would be reactivated at about 33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the LOOP based on ECCS equipment failures. If Unit 2 was restarted earlier, it scrams or operators perform a controlled shutdown due to ECCS equipment failures. The operators and TSC would make every effort possible to provide core cooling using any available means including:

~

any surviving Unit 2 ECCS equipment,

Event Sequence Evaluations Appendix C Event Trees

~

ECCS equipment from Unit I that could be crosstied to Unit 2 given that the Unit I reactor building was isolated from Zone 3 for refueling conditions, or equipment outside the reactor building of Unit I or Unit 2 such as standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service water, or pumper truck.

Most of these alternate cooling mechanisms are identified in the emergency procedures. The reactor core would begin to uncover at approximately 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months after the initiator if all these actions related to restoration of cooling to the SFPs with alternate cooling methods, isolation of Zone 3 air space, and restoration of core cooling to Unit 2 were to fail.

ORDER OF MAGNITUDE ESTIMATION OF CONDITIONAL CORE DAMAGE FRE(UENCY GIVEN THE CASE 4 INITIATOR The event tree presented in Figure C.3 presents the sequence flow path that could lead to core damage given near boiling conditions from the Case 4 initiating event. The general functional failures that would have to occur before the sequence could reach a core damage end state and order of magnitude estimations of their failure likelihoods are as follows:

Failure of alternate methods for cooling the SFPs that were not credited in the estimation of the NBF as well as failure of operators to isolate Zone 3 from the Unit 2 reactor building within approximately 33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the initiator. The failure occurs if operators do not implement alternate feed and bleed cooling to the SFPs using one of at least three possible systems and also do not isolate the Zone 3 air space from Zone 2 air space. The likelihood that these actions would fail given the approximate 25 hour2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months time period between exceeding the SFP temperature technical specification limit and failure of ECCS equipment in Unit 2 is estimated at 0. l.

Failure of and non-recovery of all Unit 2 ECCS equipment that would normally be capable of providing sufficient long term decay heat removal given the initial short term post scram functions are completed prior to failure of the ECCS equipment. The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, and other activities is estimated at 1.0.

Failure of all equipment outside the Unit 2 reactor building including fCCS equipment from Unit I that could be crosstied to Unit 2 or equipment outside the reactor building of Unit 1 or Unit 2 such as 'o standby liquid control, reactor water cleanup, fire water,'ontrol rod drive maximized, RHR service water, or pumper truck. Most of these alternate cooling mechanisms are identified in the emergency procedures.

The likelihood that these action would fail given the plant conditions, C.69

Event Sequence Evaluations Appendix C Event Trees time frame and plant staff involved, and level of other activities is estimated at 0.01.

The overall order of magnitude estimate of the conditional core damage frequency due to a initiating event in Case 4 is the product of the estimated NBF and the three general functional failure estimation above. This product is summarized in Table C.VI below.

Event Sequence Evaluation: Events Occurring in Case 5 As-Found Plant Conditions (see Figure C.4 for timeline representation of this sequence).

INITIAL PLANT CONDITIONS The plant's initial conditions are: Unit I is being refueled with the core offloaded into the SFP, Unit 2 is at normal operating conditions, the Unit 1 and Unit 2 SFPs are not cross-connected, the Unit I SFPC system and Unit 2 SFPC system are both inservice, each with three SFPC pumps running, Unit I has two trains of RHR available for operation in the SFPC assist mode, and Unit 2 has one train of RHR available for operation in the SFPC assist mode.

FROM INITIATING EVENT TO NEAR BOILING CONDITION IN THE SFPs The initiating event occurs at time zero. LOOP and EXTENDED LOOP cause a complete loss of offsite power to both units. The LOCA event involves a large, medium or small break LOCA in the operating unit and result in loss of SFPC in the operating unit and causes RHR of the LOCA unit to be unavailable for SFPC assist. Coincident with all these initiators, Unit 2 scrams and the SGTS and the recirculation system automatically starts. Plant operators respond to the event in accordance with emergency procedures and the TSC is activated within one hour after the initiator. Note that for As-Found plant conditions, the LOOP emergency procedures did not prompt operators to ensure SFPC is returned to service. Operators at both units continue with emergency actions for these events. Offsite power is restored within four hours for,the LOOP event and after restoration of offsite power, operators return systems to their normal alignments. Operators of Unit 2 may attempt to perform a rapid restart of the plant within the first 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after the LOOP. The TSC would deactivate by 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after the LOOP based on recovery of offsite power and operator's successful handling of emergency plant actions for the LOOP. For the EXTENDED LOOP and LOCA events, the TSC would not be deactivated throughout the event as mitigation activities continue. For all these event sequences, the SFPs would reach the technical specification limit of 125'F at approximately 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after the initiator assuming that operators at both units do not restore SFPC to service. Operators 'are trained to comply with technical speci,ications and the:+fore at or near 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after the LOOP, the operators would recognize the need to restore cooling to the SFPs. The operators would attempt to use the available systems to return cooling to the SFPs. This would involve use of any surplus capacity available from the EDGs to power non-safety buses under LOOP or EXTENDED LOOP conditions, to support operation of the SFPC system. By 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the LOOP, operators or the TSC

'C.70

Event Sequence Evaluations Appendix C Event Trees would likely attempt to provide an alternate means of cooling to the SFPs such as ESW, diesel backed fire water, or pumper truck for feed and bleed cooling of the SFPs. Offsite power may be recovered within 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months after the LOOP.

If the power becomes available to the non-safety bus for SFPC, operator s would attempt to restart any available SFPC system to service, cross-connect the Unit I and Unit 2 SFPs if possible, or align a train of RHR from Unit I or Unit 2 for operation in the SFPC assist mode to restore cooling to the SFPs, as system availability allows. These actions would continue persistently because the SFPs continued to heat up and approach near boiling conditions.

FROM NEAR BOILING CONDITIONS IN THE SFPs TO CORE UNCOVERY Without restoration of cooling to the SFPs within 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months after the initiator, the SFPs would reach near boiling conditions causing an increased rate of steam release from the surface of the SFP. Under SFP boiling conditions, the rate of steam. release to Zone 3 will exceed the capacity of the normal HVAC system and the SGTS for removal of this energy. If the recirculation system is left running the steam spreads to the reactor building. Within 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months after a LOOP initiator, there is the possibility for a very late recovery of offsite power. Approximately eight hours after the SFPs reach near boiling conditions (23 hours2.662037e-4 days 0.00639 hours 3.80291e-5 weeks 8.7515e-6 months after the initiator), the steam spread to the reactor building is assumed to cause ECCS equipment failure due to adverse temperature conditions. The operators and TSC would make every effort possible to provide core cooling using any available means including:

~

any surviving Unit 2 ECCS equipment, ECCS equipment from Unit I that could be crosstied to Unit 2 given that the Unit I reactor building was isolated from Zone. 3 for refueling conditions, or

~

equipment outside the reactor building of Unit I or Unit 2 such as standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service water, or pumper truck.

Most of these alternate cooling mechanisms are identified in the emergency procedures. The reactor core would begin to uncover at approximately 26 hours3.009259e-4 days 0.00722 hours 4.298942e-5 weeks 9.893e-6 months after the initiator if all these actions related to restoration of cooling to the SFPs with alternate cooling methods, isolation of Zone 3 air space, and restoration of core cooling to Unit 2 were to fail.

ORDER OF MAGNITUDE ESTIMATION OF CONDITIONAL CORE DAMAGE FREQUENCY GIVEN THE CASE 5 INITIATOR The event tree" presented in Figure C.4 presents the sequence flow path that could lead to core damage given near boiling conditions from the Case 5 initiating event. The general functional failures that would have to occur

Event Sequence Evaluations Appendix C Event Trees before the sequence could reach a core damage end state and order of magnitude estimations of their failure likelihoods are as follows:

~ Failure of alternate methods for cooling the SFPs that were not credited in the estimation of the NBF as well as failure of operators to isolate Zone 3 from the Unit 2 reactor building within approximately 23 hours2.662037e-4 days 0.00639 hours 3.80291e-5 weeks 8.7515e-6 months after the initiator. The failure occurs if operators do not implement alternate feed and bleed cooling to the SFPs using one of at least three possible systems and also do not isolate .the Zone 3 air space from Zone 2 air space. The likelihood that these actions would fail given approximately 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months between exceeding the SFP temperature technical specification limit and failure of ECCS equipment in Unit 2 is estimated at 0.1.

Failure of and non-recovery of all Unit 2 ECCS equipment that would normally be capable of providing sufficient long term decay heat removal given the initial short term post scram functions are completed prior to failure of the ECCS equipment. The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, and level of other activities is estimated at 1.0.

~

Failure of all equipment outside the Unit 2 reactor building including ECCS equipment from Unit I that could be crosstied to Unit 2 or equipment outside the" reactor building of'nit I or Unit 2 such as standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service water, or pumper truck. Host of these alternate cooling mechanisms are identified in the emergency procedures.

The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, and level of other activities is estimated at 0.01.

The overall order of magnitude estimate of the conditional core damage frequency due to an initiating event in Case 5 is the product of the estimated NBF and the three general functional failure estimation above. This product is summarized in Table C.VI below.

Event Sequence Evaluation: Events Occurring in Case I As-Found Plant Conditions (see Figure C.G for timeline representation of this sequence).

INITIAL PLANT CONDITIONS Unit I and Unit 2 Spent Fuel Pools (SFP) are initially isolated from each other with three Spent Fuel Pool Cooling (SFPC) pumps providing cooling. to each SFP. Both Units are initially operating with one train of Residual Heat Removal (RHR) available for SFPC assist mode. 0 FROM INITIATING EVENT TO NEAR BOILING CONDITION IN THE SFPs C.72

Event Sequence Evaluations Appendix C Event Trees The initiating event (earthquake) occurs at time zero and causes a loss of offsite power (LOOP) due to the seismic motion. Both Units scram and the Standby Gas Treatment System (SGTS) and recirculation systems automatically start. The plant operators respond to the seismic event and the LOOP"in accordance with the emergency procedures. Within one hour the Technical Support Center (TSC) is activated and provides support to the operators. Note that the emergency procedures for these events in the As-Found plant conditions did not prompt operators to ensure that SFPC is returned to service. Operators at both units continue with emergency actions for the first four hours after the LOOP. At the four hour point offsite power is still not restored, and the plant enters an Extended LOOP condition.

Operators align systems for emergency power supply in accordance with the emergency procedures. The TSC remains activated throughout the event and operators successfully respond to emergency plant actions for the seismic event with Extended LOOP conditions. Offsite power may be recovered within 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months after the LOOP. This recovery is not credited in the estimation of Near Boiling Frequency (NBF).

The SFPs would exceed theitechnical specification limit of 125'F approximately 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months after the seismic event if operators do not restore cooling to the SFPs. Operators are trained to complying with technical specifications and therefore by 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months after the seismic event (when the SFPs would be at about 140 F), the operators would recognize the need to restore cooling to the SFPs.

The most likely action would be to align RHR for SFPC assist mode. Power is not available for cross-connecting the pools, and each pool must be independently recovered. The TSC and Operators could attempt to power appropriate non-safety bus from the Emergency Diesel Generators (EDG)

(including the 5th unit) for support of any surviving SFPC system(s). If the above actions were not successful, the Operators and the TSC would likely attempt to provide an alternate means of cooling to the SFPs such as Emergency Service Water (ESW), diesel backed fire water, or pumper truck for feed and bleed cooling of the SFPs. These actions would continue persistently as the SFPs continued to heat up and approach near boiling conditions.

'ROM NEAR BOILING CONDITIONS IN THE SFPs TO CORE UNCOVER Without restoration of cooling to the SFPs within 50 hours5.787037e-4 days 0.0139 hours 8.267196e-5 weeks 1.9025e-5 months after the seismic event, the SFPs would reach near boiling conditions and release steam from the surface of the SFPC at an increased, rate. Under SFP boiling conditions, the rate of steam released will exceed the normal systems'apacity for removal of this energy. The steam spreads to the reactor building through the running recirculation system. Approximately eight hours after either SFP reaches near boiling conditions (58 hours6.712963e-4 days 0.0161 hours 9.589947e-5 weeks 2.2069e-5 months after the seismic. event), Both Unit's Emergency Core Cooling System (ECCS) ecgipment fails due to the encroaching steam environmeri. The operators and TSC would make every effort possible to provide core cooling using any surviving ECCS equipment or equipment outside the reactor buildings such as: standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service water, or pumper truck.

Most of these alternate cooling mechanisms are identified in the emergency 0 C.73

Event Sequence Evaluations Appendix C Event Trees procedures. The reactor core would begin to uncover at approximately 64 hours7.407407e-4 days 0.0178 hours 1.058201e-4 weeks 2.4352e-5 months after the seismic event if all these actions related to restoration of cooling to the SFPs with alternate cooling methods, isolation of Zone 3 air space, and restoration of core cooling to were to fail.

ORDER OF MAGNITUDE ESTIMATION OF CONDITIONAL CORE DAMAGE FREQUENCY GIVEN THE CASE I INITIATOR The event tree presented in Figure C.5 presents the sequence flow path that could lead to core damage given near boiling conditions from the Case I initiating event. The general functional failures that need to occur before the sequence could reach a core damage end state and order of magnitude estimations of their failure likelihoods are as follows:

Failure of alternate methods for cooling the SFPs that were n'ot credited in the estimation of the NBF as well as failure of operators to isolate Zone 3 from the reactor buildings within approximately 58 hours6.712963e-4 days 0.0161 hours 9.589947e-5 weeks 2.2069e-5 months after the initiating event'. The failure occurs if operators do not implement and bleed cooling to the SFPs using one of at least three alternate feed possible systems and do not isolate the Zone 3 air space from Zone I and Zone 2 air spaces. The alternate cooling methods all depend on non-seismically qualified equipment. However, the likelihood of total failure of all alternate methods in a small earthquake is small. For the larger seismic events where total failure is much more likely, it would also attract outside agency attention. It is expected the outside agencies, the TSC and operators would all be persistent in their recovery actions for the approximate 40 hour4.62963e-4 days 0.0111 hours 6.613757e-5 weeks 1.522e-5 months time period between exceeding the SFP temperature technical specification limit and failure of ECCS equipment. The likelihood that these actions would fail given the above conditions, is estimated at 0.5.

Failure of and non-recovery of all ECCS equipment that would normally be capable of providing sufficient long term decay heat removal given the initial short term post scram functions are completed prior to failure of the ECCS equipment. Identical failure times for all ECCS equipment available for long term cooling to both Units is unlikely. Loss of core cooling eq'uipment will highlight the operator's and TSC attention to the problem, its cause and potential solutions. Some possibility of recovery and/or avoidance is likely at this point. Given the plant conditions, time frame, plant staff involved, and level of other activities, this is estimated at 0.9.

Failure of all equipment outside the reactor buildings including ECCS equipment from either Unit that could be cross-tied to the other Unit or equipment outside the reactor buildings such as: feedwater, condensate, standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service'water, or pumper trucks. Most of these alternate cooling mechanisms are identified in the emergency procedures.

Many of these systems are not seismically qualified, but total failure C.74

Event Sequence Evaluations Appendix C Event Trees in seismic events is unlikely. In addition, resources exist from both internal and external organizations to support repair and replacement of equipment if required. The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, and level of other activities is estimated at 0.05.

The overall order of magnitude estimate of the conditional core damage frequency due to an initiating event in Case I is the product of the estimated NBF and the three general functional failure estimation above. This product is summarized in Table C.VI below.

Event Sequence Evaluation: Events Occurring in Case 3 As-Fixed Plant Conditions (see Figure C.6 for timeline representation of this sequence).

INITIAL PLANT CONDITIONS The plant's initial conditions are: Unit I is being refueled with the core offloaded into the SFP, Unit 2 is at normal operating conditions, the Unit I and Unit 2 SFPs are cross-connected, the Unit I SFPC system is out of service for maintenance and the Unit 2 SFPC system is inservice with three SFPC pumps running, the Unit I RHR system is out of service for maintenance, and the Unit 2 RHR system has one train available for operation in the SFPC assist mode.

FROM INITIATING EVENT TO NEAR BOILING CONDITION IN THE SFPs The initiating event occurs at time zero. LOOP, EXTENDED LOOP, and LOCA with LOOP cause a complete loss of offsite power to both units. LOCA and LOCA with LOOP involve a large, medium or small break LOCA in the operating unit and result in loss of SFPC and cause RHR of the LOCA unit to be unavailable for SFPC assist. Coincident with all these initiators, Unit 2 scrams and the SGTS and the recirculation system automatically starts. Plant operators respond to the event in accordance with emergency procedures and the TSC is activated within one hour after the initiator. Note that for As-Fixed plant conditions the LOOP emergency procedures provide a prompt for operators to ensure that SFPC is returned to service. Operators at both units continue with emergency actions after the initiating event and at I hour, operators recognize the need to restore cooling to the SFPs. If offsite power is not restored to the plant within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ,'he LOOP conditions are EXTENDED. Operators align systems for emergency power supply in accordance with the emergency procedures. The TSC remains activated and operators successfully respond to emergency plant actions for the EXTENDED LOOP. Within 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after the LOOP, the operators and TSC may decide to use any surplus capacity available from the EDGs to power non-safety buses to support operation of the. SFPC system. If the power becomes available to the non-safety bus for SFPC, operators would attempt to restart the Unit 2 SFPC system or return the Unit I SFPC system to 'service.

Alternatively, the operators would align any available train of RHR from Unit I or Unit 2 for operation in the SFPC assist mode as necessary to restore cooling to the SFPs. Within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months the operators or TSC may attempt to provide SFP cooling by alternate means such as: ESM, diesel backed Fire-C.75

It Event Sequence Evaluations Appendix C Event Trees Water, Pumper Truck, or other feed and bleed cooling alignments. These actions would continue persistently as the SFPs continued to heat up and approach near boiling conditions. Offsite power may be recovered later, within 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months or within 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months after the LOOP. The SFPs would reach the technica1 specification limit of 125'F at approximately 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months after the initiator assuming that operators at both units do not restore SFPC to service.

FROM HEAR BOILIHG CONDITIONS IN THE SFPs TO CORE UNCOVERY Without restoration of cooling to the SFPs within 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months after the initiator, the SFPs would reach near boiling conditions causing an increased rate of steam release from the surface of the SFP. Under SFP boiling conditions, the rate of steam release to Zone 3 will exceed the capacity of the normal HVAC system and the SGTS for removal of'his energy. If the recirculation system is left running the steam spreads to the reactor building. Approximately eight hours after the SFPs reach near boiling conditions (33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the initiator), the steam spread to the reactor building is assumed to cause ECCS equipment failure due to adverse temperature The operators and TSC would make every effort possible to provide 'onditions.

core cooling using any available means including:

~

any surviving Unit 2 ECCS equipment, ECCS equipment from Unit I that could be crosstied to Unit 2 given that the Unit I reactor building was isolated from Zone 3 for refueling conditions, or

~

equipment outside the reactor building of Unit I or Unit 2 such as standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service water, or pumper truck.

Most of these alternate cooling mechanisms are identified in the emergency procedures. The reactor core'would begin to uncover at approximately 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months after the initiator if all these'ctions related to restoration of cooling to the SFPs with alternate cooling methods, isolation of Zone 3 air space, and restoration of core cooling to Unit 2 were to fail.

ORDER OF MAGNITUDE ESTIMATION OF CONDITIONAL CORE DAMAGE FREQUENCY GIVEN THE AS-FIXED CASE 3 INITIATOR The event tree presented in Figure C.6 presents the sequence flow path that could lead to core damage given near boiling conditions from the Case 3 initiating ev@t. The general functional failures that would have 'to occur before the sequence could reach a core damage end state and order of magnitude estimations of their failure likelihoods are as follows:

~

Failure of alternate methods for cooling the SFPs that were not credited in the estimation of the NBF as well as failure of operators to isolate C.76

Event Sequence Evaluations Appendix C Event Trees Zone 3 from the Unit 2 reactor building within approximately 33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the initiator. The failure occurs if operators do not implement alternate feed and bleed cooling to the SFPs using one of at least'hree possible systems and also do not isolate the Zone 3 air space from Zone 2 air space. The likelihood that these actions would fail given approximately 25 hours between exceeding the SFP temperature technical specification limit and failure of ECCS equipment in Unit 2 is estimated at O.I.

Failure of and non-recovery of all Unit 2 ECCS equipment that would normally be capable of providing sufficient long term decay heat removal given the initial short term post scram functions are completed prior to failure of the ECCS equipment. The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, and level of other activities is estimated at 1.0.

Failure of all equipment outside the Unit 2 reactor building including ECCS equipment fram Unit I that could be crosstied to Unit 2 or equipment outside the reactor building of Unit I or Unit 2 such as standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service water, or pumper truck. Host of these alternate cooling mechanisms are identified in the emergency procedures.

The likelihood that these action would fail given the plant conditions, time frame and plant staff involved, and level of other activities is estimated at 0.01.

The overall order of magnitude estimate of the conditional core damage frequency due to a initiating event in Case 3 is the product of the estimated NBF and the three general functional failure estimation above. This product is summarized in Table C.VII below.

Event Sequence Evaluation: Events Occurring in Case 4 As-Fixed Plant Conditions (see Figure C.7 for timeline representation of this sequence).

INITIAL PLANT CONDITIONS The plant's initial conditions are: Unit I is being refueled with the core offloaded into the SFP, Unit 2 is at normal operating conditions, the Unit I and Unit 2 SFPs are cross-connected, the Unit I SFPC system is in service and the Unit 2 SFPC system is inservice each with three SFPC pumps running, the Unit I RHR system has two trains available for SFPC assist operation, and the Unit 2 RHR system has one train available for operation in the SFPC assist mode.

FROM INITIATING EVENT TO NEAR BOILING CONDITION IN THE SFPs The, initiating event occurs at time zero. LOOP, EXTENDED LOOP, and LOCA with LOOP cause a complete loss of offsite power to both units. LOCA and LOCA with LOOP involve a large, medium or small break LOCA in the operating unit and C.77

Event Sequence Evaluations Appendix C Event Trees result in loss of SFPC and cause RHR of the LOCA unit to .be unavailable for SFPC assist. Coincident with all these initiators, Unit 2 scrams and the SGTS and the recirculation system automatically starts. Plant operators respond to the event in accordance with emergency procedures and the TSC is activated within one hour after the initiator. Note that for As-Fixed plant conditions the LOOP emergency procedures provide a prompt for operators'to ensure that SFPC is returned to service. Operators at both units continue with emergency actions after the initiating event and at 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , operators recognize the need to restore cooling to the SFPs. If offsite power is not restored to the plant within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the LOOP conditions are EXTENDED. Operators align systems for emergency power supply in accordance with the emergency procedures. The TSC remains activated and operators successfully respond to emergency plant actions for the EXTENDED LOOP. Within 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months after the LOOP, the operators and TSC may decide to use any surplus capacity available from the EDGs to power non-safety buses to support operation of the SFPC system. If the power becomes available to the non-safety bus for SFPC, operators would attempt to restart the Unit 2 or Unit 1 SFPC system to service. Alternatively, the operators would align any available train of RHR from Unit 1 or Unit 2 for operation in the SFPC assist mode as necessary to restore cooling to the SFPs.

Within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months the operators or TSC may attempt to provide SFP cooling by alternate means such as: ESW, diesel backed Fire Water, Pumper Truck, or other feed and bleed cooling alignments. These actions would continue persistently as the SFPs continued to heat up and approach near boiling conditions. Offsite power may'be recovered later, within 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months or within 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months after the LOOP. The SFPs would reach the technical specification limit of 125'F at'approximately 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months after the initiator assuming that operators at both units do not restore SFPC to service.

FROM NEAR BOILING CONDITIONS IN THE SFPs TO CORE.UNCOVERY Without restoration of cooling to the SFPs within 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months after the initiator, the SFPs would reach near boiling conditions causing an increased rate of steam release from the surface of the SFP. Under SFP boiling conditions, the rate of steam release to Zone 3 will exceed the capacity of the normal HVAC system and the SGTS for removal of this energy. If the recirculation system is left running the steam spreads to the reactor building. Approximately eight hours after the SFPs reach near boiling conditions (33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the initiator), the steam spread to the reactor building is assumed to cause ECCS equipment failure due to adverse temperature conditions. The operators and TSC would make every effort possible to provide core cooling using any available means including:

any surviving Unit 2 ECCS equipment, O

ECCS equip'Sent from Unit 1 that could be crosstied to Unit 2 given that the Unit 1 reactor building was isolated from Zone 3 for refueling conditions, or C.78

Event Sequence Evaluations Appendix C Event Trees

~ equipment 'outside the reactor building of Unit I or Unit 2 such as standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service 'water, or pumper truck.

Host of these alternate cooling mechanisms are identified in the emergency procedures. The reactor core would begin to uncover at approximately 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months after the initiator if all these actions related to restoration of cooling to the SFPs with alternate cooling methods, isolation of Zone 3 air space, and restoration of core cooling to Unit 2 were to fail.

ORDER OF HAGNITUDE ESTIHATION OF CONDITIONAL CORE DAHAGE FRE(UENCY GIVEN THE AS-FIXED CASE 4 INITIATOR The event tree presented in Figure C.T presents the sequence 'flow path that could lead to core damage given near boiling conditions from the Case 4 initiating event. The general functional failures that would have to occur before the sequence could reach a core damage end state and order of magnitude estimations of their failure likelihoods are as follows:

~ Failure of alternate methods for cooling the SFPs that were not credited in the estimation of the NBF as well as failure of operators to isolate Zone 3 from the Unit 2 reactor building within approximately 33 hours3.819444e-4 days 0.00917 hours 5.456349e-5 weeks 1.25565e-5 months after the initiator. The failure occurs if operators do not implement alternate feed and bleed cooling to the SFPs using one of at least three possible systems and also do not isolate the Zone 3 air space from Zone 2 air space. The likelihood that these actions would fail given approximately 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months between exceeding the SFP temperature technical specification limit and failure of ECCS equipment in Unit 2 is estimated at O.I.

Failure of and non-recovery of all Unit 2 ECCS equipment that would normally be capable of providing sufficient long term decay heat removal given the initial short term post scram functions are completed prior to failure of the ECCS equipment. The likelihood that these actions would fail given the plant conditions, time frame and plant staff involved, level of other activities is estimated at 1.0. 'nd Failure of all equipment outside the Unit 2 reactor building including ECCS equipment from Unit I that could be crosstied to Unit 2 or equipment outside the reactor building of Unit I or Unit 2 such as standby liquid control, reactor water cleanup, fire water, control rod drive maximized, RHR service water, or pumper truck. Host of these alternate cooling mechanisms are identified in the emergency procedures.

The likelihood that these action would fail given the plant conditions, time frame and plant staff involved, and level of other activities is estimated at 0.01.

The overall order of magnitude estimate of the conditional core damage frequency due to a initiating event in Case 4 is the product of the estimated C.79

Event Sequence Evaluations Appendix C Event Trees NBF and the three general functional failure estimation above. This product is summarized in Table C.VII below.

Table C.VI SSES Site As-Found Order-of-Magnitude Estimations of CDF Hear Boiling Isolation/ ECCS Failure Equi pment Conditional Frequency Recovery Outside Annual COF Reactor Estimation Buildin Ran e From HBF 1.0 - 0.01 1.0 - 0.1 0.1 - 0.001 LOOP Case 3 3.1E-06 0.1 1.0 0.01 3.1E-09 LOOP Case 4 9.5E-07 0.1 1.0 0. 01 9. 5E-10 LOOP Case 5 1.1E-06 0.1 1.0 0.01 1.1E-09 EXLOOP Case.3 8.1E-06 0.1 1.0 0.01 8. IE-09 EXLOOP Case 4 3.2E-06 0.1 1.0 0.01 3.2E-09 EXLOOP Case 5 7.9E-06 0.1 1.0 0.01 7.9E-09 LOCA Case 3 8. 1E-06 0.1 1.0 0.01 8.1E-09 LOCA Case 4 B.BE-07 0.1 1.0 0.01 B.BE-10 LOCA Case 5 3. 1E-OS 0.1 1.0 0.01 3. 1E-09 Seismic Case 1 5.6E-07 0.5 0.9 0.05 1.3E-OB LOCA w/LOOP Case 3 8.3E-07 0.1 1.0 0.01 8.3E-10 I Total Estimated As-Found COF S.OE-OB Table C.VII SSES Site As-Fixed Order-of-Magnitude Estimations of CDF Hear Boiling Isolation/ ECCS Failure Equipnent Conditional Frequency Recovery Outside Annual COF Reactor Estimation Buildin Ran e From NBF 1.0 - 0.01 1.0 - 0.1 0.1 - 0.001 LOOP Case 3 8.5E-07 0.1 1.0 0.01 8.5E-10 LOOP Case 4 4.6E-07 0.1 1.0 0.01 4.6E-10 EXLOOP Case 3 3.5E-06 0.1 1.0 0.01 3.5E-09 EXLOOP Case=4 2. 1E-06 0.1 1.0 0.01 2.1E-09 LOCA Case 3 1.6E-06 0.1 ).0 0. 01 1. 6E-09 LOCA Case 4 1. 1E-06 0.1 1.0 0.01 1.1E-09 LOCA w/LOOP Case 3 6.9E-07 0.1 1.0 0. 01 6.9E-10 LOCA w/LOOP Case 4 4.6E-07 0.1 1.0 0.01 4. 6E-10 Totai Estimated As-Fixed COF 1.1E-OB C.80

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APPENDIX D MISCELLANEOUS INFORMATION (HRA Analysis, Assumptions - Basis and Impact)

Appendix 0 Miscellaneous Information This appendix contains the information describing the methods used to generate and select the values used for human reliability. In addition, the .

assumptions and their basis and impact, used in this evaluation are included in this appendix.

a) Human Reliability Analysis.'ontains information describing the methods used to generate and select the values used for human failure data.

b) Assumptions - Basis and Impact. Contains a listing of the assumptions used in this evaluation. The basis and impact are provided for each assumption.

HRA Analysis Appendix D Hiscellaneous Information Human-Failure Data--Human errors can contribute to system failures or otherwise impact the sequence of events such that cooling to the SFP(s) is not recovered,. 'mportant human actions are addressed in the values used in the top events of the event trees based on a simplified approach for the treatment of human errors. Proceduralized actions performed in response to evolving plant conditions were modeled as critical actions and were quantified following guidance from the Accident Sequence Evaluation Program (ASEP) provided in NUREG/CR-4772 (Swain 1987). Longer-term actions that involve repairs or innovative recoveries were treated as recovery actions. These actions were quantified based on ASEP guidance and estimations from NUREG/CR-4550 (Harper et al. 1991} in Appendix C, Section C.5, "Issue 5." Innovative Recovery Actions for Long-Term Sequences Involving Loss of Containment Heat Removal'." These techniques lead to human-error probabilities generally in the range of 0.004 to 0.1 for restart-related actions and generally in the range of O.l to 0.5 for repair or recovery actions.

The human error probability values that represent the likelihood of operator failures associated with operation of the systems and equipment presented in the event trees are estimated based on the consideration of several factors that impact operator performance. These performance shaping factors are considered within the guidance of the ASEP methodology when judging the likely failure range and selecting failure values. The factors considered generally included the following as applicable for the equipment and actions under being evaluated:

~

the number of systems and amount of equipment available that could perform the required function;

~

the degree of perceived importance to plant operators and TSC staff; the significance of the event sequence and associated disturbances that would be competing for the operator's attention; the approximate time available to complete the action; the indications of plant and system conditions that are available to the operators or TSC staff; the degree of procedural guidance'; and

~

the overall plant damage state for the event sequence.

The progression of the most important event sequences involves required operator action at every possible success path presented in the event trees.

The initial actions generally require the operators to restart a system or bring a standby train or system into service. These type actions are generally proceduralized. Subsequent actions would involve recovery action t hat involve systems not normally used for the function intended or repairions actions that require returning a system to service after completing some D.2

HRA Analysis Appendix D Miscellaneous Information maintenance activity. Guidance for these actions may not be addressed as well in procedures and these actions would take longer to perform. The actions attempted in later stages of the event sequence may involve more significant repair activities or use of alternate methods of performing the desired function. The guidance for these types of actions typically would be developed at the time of need. These actions would be taken after other more standard approaches have failed as time allows. Judgement is used to estimate the human error probability ranges and values for each of the actions considered based on consideration of the action type and the performance shaping factors involved with the action.

The specific human actions that are assessed in this evaluation to estimate human error probability values are:

Restart recovery of the SFPC system, Unit I or Unit 2 (as-available)

Place RHR in the SFPC assist mode of operation, Unit I or Unit 2 (as-available)

Cross-connect the Unit I and Unit 2 SFPs (as available)

I Repair recovery using either unit's SFPC system or RHR system in the SFPC assist mode (as-available)

Power appropriate non-safety bus using surplus EDG capacity (as-available)

Recover EDGs after their initial failure Isolate the HVAC Zone 3 air space from Zones I and 2, or provide alternate (non-routine) cooling mechanism to the SFPs to preclude failure of the ECCS equipment (as-available)

~

Connect and align alternate (non-routine) cooling mechanisms from outside the reactor building for cooling the reactor core (as-available)

~

Recover any surviving ECCS or alternate cooling equipment from either unit that can be aligned for reactor core cooling (as-available)

The Tables below show the human error probability values used for each of these operator actions for both the As-Found and the As-Fixed plant conditions and for all initiating events and cases analyzed.

D.3

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Assumptions - Basis and Impact Appendix D Miscellaneous Information The assumptions for the As-Found condition are listed below. Modifications to these assumptions to reflect the As-Fixed condition are provided at the end of this list.

Spent fuel pools (SFP) are not initially cross-connected (ice., gates are installed separating the SFPs) except Case 3 in which the SFPs are assumed to be initially cross connected.

Basis: This assumption is based on observations during the initial plant walkdown and statements by PP8L regarding past operational practices.

Impact: This assumption effects all the event trees except seismic (seismic is taken as failing crosstie) and all cases except Case 3 that assumes the SFPs are initially cross-connected. Successful completion of SFP cross-connection is necessary to credit cooling the SFPs from available systems in either or both units in the success sequences.

This assumption leads to estimated NBFs that are larger than for conditions in which the SFPs are assumed to .be initially cross-connected See As-Fixed conditions.

2. The SFPs are successfully cooled when the temperature in the SFP with the higher decay heat load does not exceed 200'F for an isolated SFP, or the temperature of the cooler SFP does not exceed 170'F when the SFPs are cross-connected.

Basis: This assumption is based on an estimate of a temperature reflecting imminent boiling conditions in which heat transfer to the room would be accelerated. A 30 degree F differential temperature between cross-connected SFPs is considered necessary to promote adequate heat transfer to prevent the hotter SFP from reaching imminent boiling conditions.

Impact: This assumption effects the time to boil estimations after a loss of SFPC event. The time to boil estimations affect the event scenario time line evaluations.

3. The heat removal capability of two or three Spent Fuel Pool Cooling (SFPC) pump and heat exchanger loops is assumed to be two or three times that of one pump and heat exchanger loop, respectively.

Basis: This assumption is based on SSES procedure OP-135-001 that indicates that the SFPC flaw rate is adjusted in multiples of 600 gpm according to the number of pump and heat exchanger loops in service.

Impact: This assumption effects the success criteria for the number of SFPC pumps and heat exchanger loops that are necessary to prevent SFP boiling.

D.6

Assumptions - Basis and Impact Appendix D Niscellaneous Information t

The heat load offloaded to the SFP is controlled such that the SFPC system maintains the temperature in the SFP within the administrative limit of 115'F. This limit is maintained by controlling: the number of SFPC pumps and heat exchangers on line, the time of the year the refueling is performed which impacts the Service Water System (SWS) temperature and associated SFPC heat exchanger capacity, the amount of fuel offloaded, and the timing after shutdown of core offload, the water volumes connected to the SFPs, and use of RHR in the SFPC assist mode necessary (i.e., outage with full core offload under summer conditions).

if Basis: This assumption is based on discussions with SSES personnel and NRC staff to set the conditions for the As-Found analysis.

Impact: The assumption effects the heat load conditions and is used to establish the various As-Found plant conditions (cases) that are analyzed. These conditions do not reflect the design basis limits of the plant regarding SWS temperature limits and SFP capacity, but reflect estimations that bound the plant's prior operating history. See Appendix A for detailed discussion of the Case definitions and their determinations.

The heat load admitted to the SFP and the pool configurations are controlled such that the time-to-boil after a loss of SFPC is greater than 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months . However, in the past, pool configurations may have been such that time-to-boil could have been between 15 and 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months for up to 10 days.

Basis: This assumption is based on discussions with SSES personnel and NRC staff to set the conditions for the As-Found analysis.

Impact: The assumption effects the heat load conditions and is used to establish the various As-Found plant conditions (cases) that are analyzed. These conditions do not reflect the design basis limits of the plant regarding SWS temperature limits and SFP capacity, but reflect estimations that bound the plant's prior operating history. See Appendix A for detailed discussion of the Case definitions and their determinations.

The operating cycle for a SSES unit is assumed to be 18 months and the duration of the refueling outage from unit shutdown to startup is assumed to be 75 days.

Basis: This assumption is based on discussions with SSES personnel and NRC staff for defining the case durations in order to estimate the annual near boiling frequency.

Impact: This assumption effects the normalized time that an SSES unit is in each condition analyzed.

D.7

Assumptions - Basis and Impact Appendix D Miscellaneous Information The Residual Heat Removal (RHR) system of each unit is assumed to have one train dedicated to reactor core decay heat removal for the following initiating events: LOOP, Extended LOOP, SBO, LOCA with LOOP, and Seismic.

Basis: This assumption is based on the expectation that the reactors of an operating unit will scram for these events and core decay heat removal needs will require dedicated support form one train of RHR.

Impact: This assumption effects the availability of the RHR system for performing in the SFPC assist mode.

The RHR system for a unit that has a LOCA initiating event will not be available for SFPC assist mode.

Basis: This assumption is based on statements made by SSES personnel.

Impact: This assumption results in the event trees for initiating events involving a LOCA not including a success path using this unit's RHR in the SFPC assist mode.

The initiating event frequency for Loss of SFPC is assumed to include the probability of the operator failing to perform immediate restart recovery actions.

Basis: This assumption is based on the implications associated with the zero failure probability technique used to estimate the initiating event frequency. This approach is taken as providing the system failure probability after operator response to minor system disturbances.

Impact: This assumption results in the event tree not showing a top event or applying a failure value of 1.0 for restart recovery of the SFPC system, D.S

Assumptions - Basis and Impact Appendix D Hiscellaneous Information During Case 2, the RHR system is assumed to have one train operating in the shutdown cooling mode. The other train is either aligned for shutdown cooling or out-of-service for maintenance. In both conditions, RHR is not available for SFPC assist mode operation. The RHR System will be in this latter condition for a total of eight days. When the RHR system is not in maintenance, one train is modeled as being available for SFPC assist to account for shutdown cooling operation providing cooling to the SFPs.

Basis: This assumption is based on the statements of SSES procedure GO-100-006 and discussions with the NRC.

Impact: This assumption results in only one train of RHR being available for realignment to the SFPC assist mode given a loss of SFPC during a majority of this Case, and in no RHR being available for seven days.

A thirty-day outage for SWS and/or RHR is assumed to occur each refueling outage after the core is offloaded, the reactor cavity gates are reinstalled, and decay heat decreases to within the capability of 2 SFPC pump/heat exchangers (Case 3 Condition). Although this outage usually lasts only ten-days it is modeled for all of Case 3 (thirty-days) with the SFPC and RHR systems out-of-service on Uni.t I and the SFPs cross-connected. This is slightly more conservative than modeling the Unit I SFPC in service with the pools not cross-connected. This small conservatism in the model is based on the assumption that administrative controls do not limit the time the SFPC system is out-of-service.

Basis: This assumption is based on discussions with SSES personnel and NRC staff.

Impact: This results in out-of-service SFPC and RHR systems during refueling. The SFPs are cooled by the operating unit's SFPC system via the cross-connect. The SFPC and RHR systems of the unit being refueled are not available for return to service in less than two days after a loss of SFPC in the operating unit. For modeling purposes, this outage is taken to last the entire duration of Case 3 (30 days). This is acceptable, as modeling the SFPC and RHR systems out-of-service on Unit I and the SFPC cross-connected is slightly more conservative than modeling the Unit I SFPC inservice with the pools not-cross-connected.

It was decided to model 'this period using the former more conservative condition because no apparent administrative controls were noted that limit the time the SFPC system is out-of-ser vice, and the conservatism is small.

D.9

Assumptions - Basis and Impact Appendix D Miscellaneous Information Five Emergency Diesel Generators (EDGs) are installed at SSES any of which can be aligned to supply designated emergency loads or SFPC system loads for either Unit I or Unit 2.

Basis: This assumption is based on SSES IPE station blackout (SBO) discussion presented in Section F. 1.2.1.4 and discussions with SSES personnel during plant walkdowns.

Impact: This assumption effects the Extended LOOP and SBO event trees in consideration of EDG availability to support subsequent recovery actions for restoration of SFPC. This assumption leads to estimated NBFs that are lower than for conditions in which EDGs are assumed to be unavailable or not recovered.

The SFPC system for one unit can provide adequate cooling for the SFP of the other unit when the gates separating both SFPs from the fuel shipping cask storage pool are removed. This cross-connected cooling arrangement requires a differential bulk water temperature between the SFPs of approximately 30'F to promote adequate water exchange.

Additional SFPC system line-up alterations to provide forced delivery of cooling water to both SFPs are not required.

Basis: This assumption is based on statements by PPLL that single unit SFPC operations have been demonstrated and engineering judgment that a 30'F temperature differential between the SFPs will provide adequate thermal driving head for mixing.

Impact: This assumption effects all the event trees except seismic (seismic is taken as failing crosstie) and requires successful completion of SFP cross-connection to credit SFPC from available systems in either or both units in the success sequences. This assumption leads to estimated NBFs that are larger than for conditions in which the SFPs are assumed to be initially cross-connected.

There are two building cranes that can remove the fuel shipping cask storage pool gates, and a qualified crane operator would be available within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of the time requested.

Basis: This assumption is based on statements made by PP8L and engineering judgment.

Impact: This assumption effects the estimation of availability of cross-connecting the SFPs. The resulting cross-connect failure value estimates are smaller than if only one crane were considered or if longer times were required for the qualified crane operator to be ready to operate the crane.

Assumptions - Basis and Impact Appendix D Miscellaneous Infopmation

15. The fuel shipping cask storage pool'is always maintained full of water.

Basis: This assumption is based on statements by PP&L and observations during the walkdown, and the need to eliminate radiation streaming from the SFPs.

Impact: This assumption effects the complexity of the cross-connecti.ng the SFPs. The result is that cross-connecting the SFPs is less complicated and takes less time than if the cask storage pit had to be filled with water prior to cross-connecting the SFPs.

16. 'Approximately eight hours are required to pl'ace the RHR system in the SFPC assist mode of operation.

Basis: This assumption is based on PP&L submittal to the NRC, dated May 24, 1993, page 19.

Impact: This assumption effects the estimation of the availability of the RHR system for SFPC assist operation. Human reliability provides a large portion of this estimation and in this case results in larger unavailability, due to estimated human error probability than would be estimated for a less complicated procedure that takes less time to perform (i.e., significantly less than 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months ).

17. There are two diesel fire pumps that can provide makeup to either Unit's SFP under SBO conditions.

Basis: This assumption is based on discussions with PP&L and the Final Safety Analysis Report (FSAR) and piping and instrument diagram (P&ID) information.

Impact: This assumption effects the considerations made for longer term innovative recovery actions by the TSC. These innovative recovery actions involve alternate cooling methods and are used in developing order-of-magnitude estimates of the potential contribution to core damage.

Assumptions - Basis and Impact Appendix D miscellaneous Information

18. The gates separating the reactor cavity from the SFP are provided with redundant positive-sealing devices and alarm features with alarm indication of seal leakage and a low SFP level. Any significant loss of SFP inventory would require a concurrent major rupture of both independent sealing devices. This potential failure, as an initiating event for loss of SFPC, is not modeled since it is considered not credible.

Basis: This assumption is based on statements by PP&L and a submittal from PP&L to the NRC in response to IE Bulletin 84-03 concluding that gross failure of the reactor cavity seals is not credible.

Impact: This assumption effects the possible initiating events considered and renders the potential for drain down of the SFP incredible.

lg. The system and support system models used maintenance unavailability values representative of normal plant operations for all cases analyzed unless noted otherwise. Refueling outage and associated maintenance activities are assumed to be scheduled and performed such that these systems have availabilities comparable to normal operating conditions.

Basis: This assumption is based on SSES practices of maintaining decay heat removal systems and/or demonstrated alternate cooling capability at technical specification requirements plus one additional method; or when technical specifications do not apply, one method plus a backup method are available (NDAP-00-06l2, NDAP-00-0613, and Nuclear Safety Assessment Group Report 4-93 regarding Outage Safety Review).

Impact: This assumption effects the potential availability of any plant system that provides or supports the SFPC function including backup systems. Consideration of the spectrum of possible outage maintenance conditions and their effects is considered a shutdown risk issue beyond the scope of this analysis.

D.12

Assumptions - Basis and Impact Appendix D Miscellaneous Information

20. Equipment that is located in the reactor buildings (HVAC Zones I and 2) and is critical for performing safety functions will experience heatup after the onset of boiling in the SFP if not isolated from HVAC Zone 3.

Successful isolation of HVAC Zone 3 requires that the regirculation system be shut off and the Standby Gas Treatment System (SGTS) be operating. When HVAC Zone 3 is not isolated, the safety equipment in HVAC Zones I and 2 reaches equipment failing critical temperatures approximately 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after'he onset of boiling in the SFP. During refueling outages, the reactor building for the unit being refueled is isolated from HVAC Zone 3 and therefore the safety equipment in that unit will not experience heatup from boiling in the SFPs. Mith the recirculation fans off, the SGTS would fail approximately 15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months after the SFP begins to boil and'the ECCS equipment would fail approximately 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the SFP begins to boil.

Basis: PNL discussions with the NRC after the second plant walkdown; PPEL telephone discussion with Mr. Steve Jones (NRC) providing verbal response to questions from NRC and PNL discussed in March 25, 1994 telephone call; PP8L letter to NRC dated August 16, 1993 (PLA-4012),

Attachment, page 7; and SSES procedures G0-100-006, Rev 16, "Cold Shutdown, Defueled, and Refueling."

Impact: This effects the event sequence time line and the Zone 3 isolation considerations for the order-of-magnitude estimation of potential for contribution to core damage for. the most important event sequences.

2l. A reactor scram does not occur coincident with the loss of SFPC initiating event. Plant management is assumed to direct a plant shutdown at either, the approximate time of onset-of-boiling in the SFP or when the area temperature in HVAC Zone 3 reaches 125'F, whichever occurs first.

Basis: Judgement that SSES management would direct plant shutdown after the area temperatures exceeded the normal maximum temperature limit assumed in the FSAR (typically 104 F). SSES procedures ON-135(235)-001 and EP-PS-]02 (As-Fixed plant condition revisions) caution about potential adverse effects on safety related equipment.

Impact: This effects the time line evaluation for equipment performing post-scram reactor core cooldown functions prior to heatup of reactor building.

J ~

~A g 'l I

Assumptions - Basis and Impact Appendix 0 Miscellaneous Information

22. A reactor scram occurs coincident with all initiating events except loss of SFPC. Safety functions begin at the time of the reactor scram as does the start of SFP heatup.

Basis: A loss of SFPC in itself does not immediately have an impact on safe power operations. For modeling purposes, the initiating event for all other loss of SFPC events is treated as causing a reactor scram.

Impact: This effects the time line evaluation for equipment performing post-scram reactor core cooldown functions prior to heatup of reactor building.

23. The condensate and feedwater systems have all their active'components necessary for post-scram alignment feeding/makeup to the reactor pressure vessel located in the turbine building and the turbine building does not experience heatup in response to SFP heatup. The condensate and feedwater systems are also assumed to be failed after a seismic event or loss of offsite power.

Basis: The observations made during the plant walkdown and SSES IPE information (PP8L 1993b, pages F-5, A-85, and A-96).

Impact: This effects the availability of systems that could be used for alternate core cooling in assisting the potential for contribution to core damage.

24. The flood, loss of SWS, and pipe break initiating event impacts are considered local events impacting only the SFPC equipment. Plant wide floods, loss of SWS, or pipe breaks with global effects, as well as the potential for consequential damage to other safety-related equipment from these events was not considered.

Basis: Evaluation of plant wide effects are beyond the scope of this analysis, these events were only considered as possible loss of SFPC initiators for this bounding case analysis.

Impact: This effects the loss of SFPC initiating event frequencies for local failures affecting SFPC operation and results in initiating events that are somewhat conservative since they may double count local failures.

0.14

Assumptions - Basis and Impact Appendix D Miscellaneous Information

25. Several methods exist for backup SFPC that are not credited in the NBF evaluation model. These methods would prevent SFP boiling or delay the time to SFP boiling conditions and include:

Feed and bleed to SFPs. Feed is provided through Emergency Service Water (ESW) (hard piped and EDG backed) or using fire hose (requires operators to run hose reel to SFPs or to hook up to ESW hard pipe). Bleed is via the overflow through the SFP skimmer surge tank line.

Use the diesel powered fire water pumps for discharge to the SFPs through connection to existing hard pipe systems (i.e., ESW).

Use of RHR in the shut down cooling mode of operation with discharge to the Reactor Pressure Vessel (RPV) and simultaneously to the SFPs (although not proven to prevent SFP boiling it would certainly delay the heatup).

Basis: These alternate cooling methods are not procedurally directed and would require innovative recovery actions. These types of actions are considered in the order-of-magnitude estimation of potential for contribution to core damage from the most important event sequences.

Impact: This effects the recovery paths evaluated in the NBF and CDF event trees.

26. Flooding to the reactor building from SFP condensate and/or overflow is directed'to the reactor building sumps and this water is isolated from Emergency Core Cooling System (ECCS) equipment in the reactor buildings except one train of core spray.

Basis: The sump room has water tight doors and drain line isolation valves to barrier it from the reactor building equipment. The sump room and ECCS equipment rooms have level indication and alarms and the sump room has the ability to be pumped out from overhead access ports using portable pumping devices.

Impact: This effects the consideration of potential for ECCS equipment failure due to SFP overflow drainage and condensation.

27. The Technical Support Center (TSC) is manned and operational within one hour after the initiating event. The TSC staff will facilitate preparation of appropriate recovery action procedures to support mitigation of the event.

Basis: This is a designated function of the TSC.

Impact: This effects the activities time line evaluation for the most important event sequences.

0.15

Assumptions - Basis and Impact Appendix D Niscellaneous Information

28. SFP level and temperature indication in the control room was not improved in the As-Found conditions.

Basis: PP&L letter to NRC dated August 16, 1993, Attachment, page 14.

Impact: This effects the evaluation of human actions for mitigation of loss of SFPC events.

29. The HVAC ductwork low points did not have drains.

Basis: PP8L letter to NRC dated August 16, 1993, Attachment, page. 14.

Impact: This effects the evaluation of human actions for mitigation of loss of SFPC events.

30. The procedures for placing RHR in the SFPC assist mode'id not require raising the SFP level before running the RHR system in the SFPC assist mode Basis: PP&L letter to NRC dated August 16, 1993, Attachment, page 14.

Impact: This effects the evaluation of human actions for mitigation of loss of SFPC events.

31. The LOOP emergency procedure did not prompt the operators to consider that the SFPC needs to be restarted.

Basis: PP8L letter to NRC dated August 16, 1993, Attachment, page 14.

Impact: This effects the evaluation of human actions for mitigation of loss of SFPC events.

32. The administrative controls to maintain at least 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months to SFP boiling under a loss of SFPC were not formally controlled or documented.

Basis: Discussions with PP&L and NRC during meetings before the second plant walkdown.

Impact: This effects case determination definition differences between the As-Found and As-fixed plant conditions.

D.16

Assumptions - Basis and Impact Appendix D Miscellaneous Information

33. The emergency procedures suggest a variety of ways to maintain core cooling in the event the ECCS systems failed,'ncluding: feedwater, condensate, CRD maximized, RHR-SWS cross-tie, fire water. system, CRD from other unit, ECCS keep fill system, SLC boron tank, SLC demineralized cross-tie.

Basis: Emergency procedure flow chart diagram for RPV Control 102.

Impact: This effects the systems considered for alternate core cooling methods for assessing the potential for contribution to core damage for the most important event sequences.

34. Support systems are required as identified in the matrix of information provided by SSES taken from the IPE.

Basis: The support system requirements as evaluated by SSES in their IPE.

Impact: The effects of the fault tree models used to estimate system failure likelihoods for the NBF evaluation.

35. The aluminum siding at some locations in the reactor building has hinged panels that would pivot out and relieve pressure in the building due to the steam environment and thus help to remove energy and reduce temperature.

Basis: Discussions with PPEL and NRC during meetings before the second plant walkdown.

Impact: This effects the consideration of potential for adverse conditions to develop in the reactor building.

D.17

Assumptions - Basis and Impact Appendix 0 Miscellaneous Information AS-FIXED ASSUNPTIONS The assumptions for the As-Fixed conditions differ from the As-Found conditions as outlined below.

1. Spent fuel pools are initially cross-connected (i.e., gates that could separate the SFPs have been removed) for the entire operating cycle except as may be necessary for some off-normal or emergency situation.

Basis: Discussions with PP&L and NRC prior to the second plant walkdown and observations during the second plant walkdown.

Impact: This effects the event trees, success criteria, and case determination for the NBF evaluations.

2. SFP level and temperature indication in the control room has been improved.

Basis: PP&L letter to NRC dated August 16, 1993, Attachment, page 14.

Impact: This effects the evaluation of human actions for mitigation of loss of SFPC events.

3. The HVAC ductwork has low point drains.

Basis: PP&L letter to NRC dated August 16, 1993, Attachment, page 14, Impact: This effects the evaluation of human actions for mitigation of loss of SFPC events.

4. The procedures for placing RHR in the SFPC assist mode require raising the SFP level before running the RHR system in the SFPC assist mode.

Basis: PP&L letter to NRC dated August 16, 1993, Attachment, page 14, Impact: This effects the evaluation of human actions for mitigation of loss of SFPC events.

5. The LOOP emergency procedure does prompt the operators to restore cooling to the SFPs.

Basis: PP&L letter to NRC dated August 16, 1993, Attachment, page 14.

Impact: This effects the evaluation of human actions for mitigation of loss of SFPC events.

Assumptions - Basis and Impact Appendix D Miscellaneous Information The administrative controls to maintain at least 25 hours2.893519e-4 days 0.00694 hours 4.133598e-5 weeks 9.5125e-6 months to SFP boiling under a loss of SFPC are formally controlled and documented. This may require use of RHR in the SFPC assist mode for a full core offloa'd under summer conditions.

Basis: PP&L letter to NRC dated August 16, 1993, Attachment, page 14.

Impact: This effects the evaluation of human actions for mitigation of loss of SFPC events.

D.19

O~

't

ML17158A633

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